DP Extractive Activities.fm

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April 2010
Discussion Paper
DP/2010/1
Extractive Activities
Comments to be received by 30 July 2010
Prepared for the IASB by the
following staff of the national
accounting standard-setters in
Australia, Canada, Norway and
South Africa:
Glenn Brady
Riaan Davel
Sue Ludolph
Aase Lundgaard
Joanna Spencer
Mark Walsh
Discussion Paper
Extractive Activities
Comments to be received by 30 July 2010
DP/2010/1
This discussion paper Extractive Activities is published by the International Accounting
Standards Board (IASB) for comment only.
The paper was prepared by a project team of staff from four national standard-setters
and sets out the team’s findings and recommendations.
Comments on the contents of the discussion paper should be submitted in writing so
as to be received by 30 July 2010. Respondents are asked to send their comments
electronically to the IASB website (www.iasb.org), using the ‘Open to Comment’ page.
All responses will be put on the public record unless the respondent requests
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by good reason, such as commercial confidence.
The IASB, the International Accounting Standards Committee Foundation (IASCF), the
authors and the publishers do not accept responsibility for loss caused to any person
who acts or refrains from acting in reliance on the material in this publication,
whether such loss is caused by negligence or otherwise.
Copyright © 2010 IASCF®
ISBN: 978-1-907026-66-9
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EXTRACTIVE ACTIVITIES
CONTENTS
paragraphs
BACKGROUND
INVITATION TO COMMENT
PREFACE
CHAPTER 1 – SCOPE AND APPROACH
1.1–1.24
Scope
1.1–1.6
Research parameters
1.7–1.14
Common requirements across the minerals and oil and gas industries
Avoid issues of general application
The Framework
Scope of financial reporting
1.8–1.11
1.12
1.13
1.14
Financial reporting issues
1.15–1.18
Users’ needs
1.19–1.24
CHAPTER 2 – DEFINITIONS OF RESERVES AND RESOURCES
Introduction
2.1–2.68
2.1
Reserves and resources
2.2–2.6
Financial reporting needs
2.7–2.8
Alternatives for defining reserves and resources
Developing new definitions
Consistent definitions
2.9–2.10
2.9
2.10
Existing reserves and resources definitions
2.11–2.13
Comparison study
2.14–2.23
Wide acceptance
A broad and comprehensive scope
SEC definitions
The UNFC
2.16
2.17
2.18–2.20
2.21–2.23
Comparison study findings
2.24–2.45
Comparable concepts
Differing concepts
2.27–2.40
2.41–2.45
Comparability of definitions to accounting principles
Economic assumptions
Conditions to be satisfied before a reserve is recognised
Project team’s view on definitions
2.46–2.66
2.49–2.63
2.64–2.66
2.67–2.68
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DISCUSSION PAPER MARCH 2010
CHAPTER 3 – ASSET RECOGNITION
3.1–3.68
Introduction
3.1–3.2
Asset recognition—current practice
3.3–3.6
Asset recognition—using the Framework
3.7–3.11
Applying the Framework to extractive activities
Legal rights
Information
Additional rights and approvals
Properties in the development or production phases
Prospecting activities
Derecognition
Plant and equipment
Project team’s view on recognition of assets
3.12–3.32
3.13–3.17
3.18–3.21
3.22
3.23–3.28
3.29
3.30–3.31
3.32
3.33–3.38
Presentation of the legal rights
3.36–3.38
Unit of account selection
3.39–3.57
Unit of account considerations for extractive activities
Geographical dimensions
Asset components
3.42–3.43
3.44–3.57
3.58–3.64
Project team’s view on unit of account
3.65–3.68
CHAPTER 4 – ASSET MEASUREMENT
4.1–4.85
Introduction
4.1–4.3
Existing practice
4.4–4.7
Current value
4.8–4.37
Approaches for estimating fair value
4.11–4.37
Historical cost
4.38–4.76
Historical cost measurement after initial recognition
Depreciation
Impairment
4.44
4.45–4.49
4.50–4.76
A mixed measurement basis
4.77–4.78
Income recognition
4.79–4.82
Project team’s view on measurement
4.83–4.85
CHAPTER 5 – DISCLOSURE
5.1–5.101
Introduction
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5.1–5.2
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EXTRACTIVE ACTIVITIES
A disclosure objective for extractive activities
5.3–5.11
Evaluating value
Evaluating performance
Evaluating risk and uncertainty
5.6–5.8
5.9–5.10
5.11
Guiding principles relevant to the disclosure objective
5.12–5.23
Common disclosure requirements
Scope and constraints of financial reporting
5.13–5.14
5.15–5.23
Disclosures
5.24–5.25
Disclosure type 1: Reserve quantities
5.26–5.71
Categories of reserves to be disclosed
Reserves attributable to the entity
Disaggregated disclosure of reserve quantities
Basis of estimation
Disclosure of the main assumptions
Sensitivity analysis
Reconciliation of changes in quantities from year to year
5.26–5.30
5.31–5.39
5.40–5.47
5.48–5.49
5.50–5.59
5.60–5.67
5.68–5.71
Disclosure type 2: Value-based information
5.72–5.75
Disclosure type 2A. Current value measurement
5.76–5.94
Alternative A—valuation range estimates based on fair value
measurement principles
Alternative B—discounted cash flow measurement of proved and
probable reserves
5.77–5.79
5.80–5.94
Disclosure type 2B: Fair value measurement – disclosures that amplify
the fair value measurement of minerals or oil and gas properties
5.95–5.97
Disclosure type 3: Production revenues
5.98–5.99
Disclosure type 4: Time series of exploration, development and
production cash outflows
CHAPTER 6 – PUBLISH WHAT YOU PAY PROPOSALS
5.100–5.101
6.1–6.51
Introduction
6.1–6.3
Background
6.4
PWYP proposals
6.5–6.6
Disclosure in financial reports
6.7
Relationship between the PWYP proposals and the objectives
of financial reporting
Users of the PWYP proposals
Scope of financial reports
6.8–6.12
6.9–6.10
6.11–6.12
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DISCUSSION PAPER MARCH 2010
Usefulness of the PWYP proposals to capital providers
Relevance of the scale of an entity’s operations in individual countries
for assessing country-specific investment risks
Relevance of payment to governments for assessing country-specific
investment risks and reputational risk
Cost-benefit implications of the PWYP proposals
PWYP disclosure 1:
PWYP disclosure 2:
PWYP disclosure 3:
PWYP disclosure 4:
PWYP disclosure 5:
PWYP disclosure 6:
Payments to governments
Reserves
Production quantities
Production revenues
Development and production costs
Disclosure of key subsidiary
and property information
Summary
6.13–6.25
6.14–6.17
6.18–6.25
6.26–6.47
6.27–6.37
6.38–6.40
6.41–6.42
6.43–6.44
6.45
6.46–6.47
6.48–6.51
APPENDICES
A
Description of Extractive Activities
B
Overview of Minerals and Oil and Gas Reserves and Resources Definitions
C
User Survey Process
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EXTRACTIVE ACTIVITIES
Background
In 2004 the International Accounting Standards Board set up an international
project team comprising staff from the national standard-setters in Australia,
Canada, Norway and South Africa to research the accounting for extractive
activities. This discussion paper presents the project team’s findings and
recommendations as a result of that research. The Board has discussed the project
team’s findings at public meetings but has not developed preliminary views on
any of the project team’s recommendations or made any related technical
decisions.
Later in 2010, the Board will consult publicly on the composition of its technical
agenda following completion in June 2011 of its Memorandum of Understanding
commitments. Among other projects, that public consultation process will
identify the extractive activities project as a candidate for inclusion in the Board’s
agenda. The comments received in relation to this discussion paper will also
assist the Board in making its agenda decisions.
If the Board adds a project on extractive activities to its agenda, the Board will use
the discussion paper, and the comments it receives, as the basis for its initial
deliberations on the project. At that time, the Board will decide whether, in the
light of the responses received, it would be appropriate to proceed to the
development of an exposure draft as the next step in its due process or whether it
is necessary for the Board to publish its own discussion paper.
The Board is grateful to the participating national standard-setters for supporting
the research phase of this project and to the authors of the discussion paper.
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DISCUSSION PAPER MARCH 2010
Invitation to comment
The Board invites comments on all matters in this discussion paper, particularly
on the questions set out below and on whether, overall, the project team’s
recommendations, if implemented, would improve the financial reporting of
entities engaged in extractive activities. Comments are most helpful if they:
•
address the questions as stated;
•
indicate the specific paragraph or paragraphs to which the comments
relate;
•
contain a clear rationale; and
•
describe any alternatives the Board should consider.
Respondents need not comment on all of the questions. Respondents are also
encouraged to comment on any additional issues within the scope of the
discussion paper.
The Board will consider all comments received in writing by 30 July 2010.
Question 1 – Scope of extractive activities
In Chapter 1 the project team proposes that the scope of an extractive activities
IFRS should include only upstream activities for minerals, oil and natural gas.
Do you agree? Are there other similar activities that should also fall within the
scope of an IFRS for extractive activities? If so, please explain what other activities
should be included within its scope and why.
Question 2 – Approach
Also in Chapter 1, the project team proposes that there should be a single
accounting and disclosure model that applies to extractive activities in both the
minerals industry and the oil and gas industry. Do you agree? If not, what
requirements should be different for each industry and what is your justification
for differentiating between the two industries?
Question 3 – Definitions of minerals and oil and gas reserves and
resources
In Chapter 2 the project team proposes that the mineral reserve and resource
definitions established by the Committee for Mineral Reserves International
Reporting Standards and the oil and gas reserve and resource definitions
established by the Society of Petroleum Engineers (in conjunction with other
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EXTRACTIVE ACTIVITIES
industry bodies) should be used in an IFRS for extractive activities. Do you agree?
If not, how should minerals or oil and gas reserves and resources be defined for
an IFRS?
Question 4 – Minerals or oil and gas asset recognition model—
recognition
In Chapter 3 the project team proposes that legal rights, such as exploration
rights or extraction rights, should form the basis of an asset referred to as a
‘minerals or oil and gas property’. The property is recognised when the legal
rights are acquired. Information obtained from subsequent exploration and
evaluation activities and development works undertaken to access the minerals
or oil and gas deposit would each be treated as enhancements of the legal rights.
Do you agree with this analysis for the recognition of a minerals or oil and gas
property? If not, what assets should be recognised and when should they be
recognised initially?
Question 5 – Minerals or oil and gas asset recognition model—unit of
account selection
Chapter 3 also explains that selecting the unit of account for a minerals or oil and
gas property involves identifying the geographical boundaries of the unit of
account and the items that should be combined with other items and recognised
as a single asset.
The project team’s view is that the geographical boundary of the unit of account
would be defined initially on the basis of the exploration rights held. As exploration,
evaluation and development activities take place, the unit of account would
contract progressively until it becomes no greater than a single area, or group of
contiguous areas, for which the legal rights are held and which is managed
separately and would be expected to generate largely independent cash flows.
The project team’s view is that the components approach in IAS 16 Property, Plant
and Equipment would apply to determine the items that should be accounted for as
a single asset.
Do you agree with this being the basis for selecting the unit of account of a minerals
or oil and gas property? If not, what should be the unit of account and why?
Question 6 – Minerals or oil and gas asset measurement model
Chapter 4 identifies current value (such as fair value) and historical cost as
potential measurement bases for minerals and oil and gas properties.
The research found that, in general, users think that measuring these assets at
either historical cost or current value would provide only limited relevant
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DISCUSSION PAPER MARCH 2010
information. The project team’s view is that these assets should be measured at
historical cost but that detailed disclosure about the entity’s minerals or oil and
gas properties should be provided to enhance the relevance of the financial
statements (see Chapters 5 and 6).
In your view, what measurement basis should be used for minerals and oil and gas
properties and why? This could include measurement bases that were not
considered in the discussion paper. In your response, please explain how this
measurement basis would satisfy the qualitative characteristics of useful
financial information.
Question 7 – Testing exploration properties for impairment
Chapter 4 also considers various alternatives for testing exploration properties
for impairment. The project team’s view is that exploration properties should not
be tested for impairment in accordance with IAS 36 Impairment of Assets. Instead,
the project team recommends that an exploration property should be written
down to its recoverable amount in those cases where management has enough
information to make this determination. Because this information is not likely
to be available for most exploration properties while exploration and evaluation
activities are continuing, the project team recommends that, for those
exploration properties, management should:
(a)
write down an exploration property only when, in its judgement, there is a
high likelihood that the carrying amount will not be recoverable in full;
and
(b)
apply a separate set of indicators to assess whether its exploration
properties can continue to be recognised as assets.
Do you agree with the project team’s recommendations on impairment? If not,
what type of impairment test do you think should apply to exploration
properties?
Question 8 – Disclosure objectives
In Chapter 5 the project team proposes that the disclosure objectives for
extractive activities are to enable users of financial reports to evaluate:
(a)
the value attributable to an entity’s minerals or oil and gas properties;
(b)
the contribution of those assets to current period financial performance; and
(c)
the nature and extent of risks and uncertainties associated with those
assets.
Do you agree with those objectives for disclosure? If not, what should be the
disclosure objectives for an IFRS for extractive activities and why?
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Question 9 – Types of disclosure that would meet the disclosure
objectives
Also in Chapter 5, the project team proposes that the types of information that
should be disclosed include:
(a)
quantities of proved reserves and proved plus probable reserves, with the
disclosure of reserve quantities presented separately by commodity and by
material geographical areas;
(b)
the main assumptions used in estimating reserves quantities, and a
sensitivity analysis;
(c)
a reconciliation of changes in the estimate of reserves quantities from year
to year;
(d)
a current value measurement that corresponds to reserves quantities
disclosed with a reconciliation of changes in the current value
measurement from year to year;
(e)
separate identification of production revenues by commodity; and
(f)
separate identification of the exploration, development and production
cash flows for the current period and as a time series over a defined period
(such as five years).
Would disclosure of this information be relevant and sufficient for users?
Are there any other types of information that should be disclosed? Should this
information be required to be disclosed as part of a complete set of financial
statements?
Question 10 – Publish What You Pay disclosure proposals
Chapter 6 discusses the disclosure proposals put forward by the Publish What You
Pay coalition of non-governmental organisations. The project team’s research
found that the disclosure of payments made to governments provides
information that would be of use to capital providers in making their investment
and lending decisions. It also found that providing information on some
categories of payments to governments might be difficult (and costly) for some
entities, depending on the type of payment and their internal information
systems.
In your view, is a requirement to disclose, in the notes to the financial statements,
the payments made by an entity to governments on a country-by-country basis
justifiable on cost-benefit grounds? In your response, please identify the benefits
and the costs associated with the disclosure of payments to governments on a
country-by-country basis.
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DISCUSSION PAPER MARCH 2010
Preface
P1
Entities engaged in minerals or oil and gas extractive activities are an
important part of international capital markets. However, some
extractive activities—and the assets or expenditures associated with these
activities—are not comprehensively addressed by International Financial
Reporting Standards (IFRSs). There are scope exclusions in IFRSs that
might otherwise apply to some of these activities, most notably in IAS 16
Property, Plant and Equipment and IAS 38 Intangible Assets. Furthermore,
although IFRS 6 Exploration for and Evaluation of Mineral Resources addresses
the accounting for exploration and evaluation expenditures, it was
developed as an interim measure to allow (with some limitations) entities
adopting IFRSs to continue to apply their existing accounting policies for
these expenditures. This absence of comprehensive IFRS literature has
contributed to continuing divergence in the international financial
reporting of extractive activities. Concerns have also been raised that
some accounting practices might not be consistent with the IASB
Framework for the Preparation and Presentation of Financial Statements.
P2
This discussion paper is the first step towards a possible IFRS for
extractive activities that would address those concerns and replace IFRS 6.
History
P3
The IASB’s predecessor organisation, the International Accounting
Standards Committee (IASC) began a project on accounting by entities in
the extractive industries in 1998. The main reasons for undertaking this
project were to address the divergence of views on:
(a)
the extent to which the costs of finding, acquiring and developing
minerals or oil and gas reserves and resources should be
capitalised;
(b)
the methods of depreciating (or amortising) capitalised costs;
(c)
the degree to which quantities and values of minerals or oil and gas
reserves and resources, rather than costs, should affect recognition,
measurement and disclosure; and
(d)
the definition and measurement of minerals and oil and gas
reserves and resources.
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P4
In November 2000 the IASC Steering Committee on Extractive Industries
published an Issues Paper Extractive Industries, which attracted 52 comment
letters. Where relevant, the Issues Paper and comments received in
response have been considered by the project team in developing this
discussion paper.
P5
The IASB was constituted in 2001 as successor to the IASC. In July 2001
the IASB announced that it would restart the project when agenda time
permitted. In September 2002 the IASB decided it was not feasible to
complete a comprehensive project on accounting for extractive activities
in time for the many entities that would adopt IFRSs in 2005. However,
the IASB decided it was necessary to provide principles on the treatment
of exploration and evaluation costs for entities applying IFRSs in 2005.
Accordingly, IFRS 6 was issued in December 2004. The IASB’s objectives in
issuing IFRS 6 were:
P6
*
(a)
to make limited improvements to accounting practices for
exploration and evaluation expenditures, without requiring major
changes that might be reversed when the IASB undertakes a
comprehensive review of accounting practices used by entities
engaged in the exploration for and evaluation of mineral
resources;*
(b)
to specify the circumstances in which entities that recognise
exploration and evaluation assets should test such assets for
impairment in accordance with IAS 36 Impairment of Assets; and
(c)
to require entities engaged in the exploration for and evaluation of
mineral resources to disclose information about exploration and
evaluation assets, the level at which such assets are assessed for
impairment and any impairment losses recognised.
Also in 2004, the IASB initiated a research project to undertake a
comprehensive assessment of accounting for extractive activities.
The research project was undertaken by a project team that comprised
staff from the national accounting standard-setters in Australia, Canada,
Norway and South Africa. An advisory panel that included members from
entities operating in the minerals and the oil and gas industries,
accounting firms, users of financial reports and securities regulators
from around the world assisted the project team throughout the research
project. Other industry groups, including the Committee for Mineral
Reserves International Reporting Standards, the Society of Petroleum
IFRS 6 uses the term ‘mineral resources’ as a general reference for minerals, oil, natural
gas and similar non-regenerative resources.
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DISCUSSION PAPER MARCH 2010
Engineers Oil and Gas Reserves Committee, and the United Nations Ad
Hoc Group of Experts on the Harmonisation of Fossil Energy and Mineral
Resources, and other industry and investment professionals were
consulted at various stages throughout the project. The project team
appreciates the contributions that these groups and individuals made to
the research project.
P7
This discussion paper presents the results of the research project. All the
conclusions in the paper are those of the project team.
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Chapter 1 – Scope and approach
Scope
1.1
This discussion paper addresses financial reporting issues associated with
exploring for and finding minerals, oil and natural gas deposits,
developing those deposits and extracting the minerals, oil and natural
gas. These are referred to as extractive activities or, alternatively, as
upstream activities. A brief description of these activities is provided in
Appendix A.
1.2
Minerals, oil and natural gas are non-regenerative natural resources.
In other words, they cannot be replaced in their original state after
extraction. Minerals are naturally occurring materials in or on the
earth’s crust that include metallic ores (such as copper, gold, silver, iron,
nickel, lead and zinc), other industrial minerals (non-metallic minerals
and aggregates), gemstones, uranium and fossilised organic material
(coal). Oil and natural gas, often referred to collectively as petroleum, can
be defined as a naturally occurring mixture consisting of hydrocarbons in
the gaseous, liquid or solid phase (such as tar sands or oil shale). This
paper refers to these non-regenerative natural resources collectively as
either minerals or oil and gas, as appropriate.
1.3
Extractive activities are subject to several significant uncertainties.
During exploration it is common to have insufficient data to evaluate
whether a deposit of minerals or oil and gas will be developed and will
generate future net cash inflows from the extraction and sale of the
minerals or oil and gas. These uncertainties revolve around the quantity
of minerals or oil and gas that exist and can be extracted given the
geological, technical and economic conditions. While such uncertainties
may decrease over time as knowledge of the geology of the deposit
improves and better estimates can be made about the quantity of
minerals or oil and gas that can be extracted and future economic
conditions, these uncertainties remain even during the development and
production phases. There is also no direct relationship between the risks
and rewards of a particular exploration programme. For example, a very
small expenditure may result in a major find while substantially larger
expenditures may result in nothing being found.
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DISCUSSION PAPER MARCH 2010
1.4
1.5
*
There are other activities that some might view as having some similar
characteristics to exploring for and finding minerals or oil and gas
deposits, developing those deposits and extracting the minerals or oil and
gas, such as the production of geothermal energy and the extraction of
minerals from seawater. These activities are not regarded as extractive
activities because they either:
(a)
share a similar process to extractive activities and face similar
risks, but are not strictly non-regenerative resources
(eg geothermal energy projects); or
(b)
involve a process of extracting non-regenerative resources, but face
risks that are more in the nature of the risks facing manufacturing
activities or other production processes (eg the extraction of
minerals from seawater) and so are very different from the risks
associated with exploring for, developing and extracting minerals
or oil and gas.
Including these other activities within the scope of extractive activities:
(a)
would have implications for the design of an IFRS for extractive
activities, because a separate disclosure model and/or
modifications to the accounting model might need to be developed
to address the different risks and characteristics of those activities.
Among other things, this would include the development of
definitions that are comparable to the definitions of minerals and
oil and gas reserves and resources.*
(b)
would potentially extend the project scope to related areas, and
make the project open-ended and more difficult to manage and
progress.
In August 2008, the geothermal industry in Australia issued the Australian Code for Reporting
of Exploration Results, Geothermal Resources and Geothermal Reserves (known as the Geothermal
Reporting Code). If geothermal is to be included within the scope of an IFRS for extractive
activities, the mapping of the CRIRSCO Template (for minerals) to the Petroleum Resource
Management System (as discussed in Chapter 2) will need to be extended to include
comparisons to the Geothermal Reporting Code. This is not expected to cause significant
difficulty because it is modelled on the CRIRSCO Template. However, there may be
different geothermal reporting systems that apply in different regions. Page 1 of the
Geothermal Reporting Code notes that the methodology of the Code will ‘be applicable to
the type of geothermal projects that are likely to be undertaken in Australia, given that
many of the Australian [projects] … are different from most of those which have so far been
commercially developed in other countries’. For these reasons, the research has not
specifically included geothermal projects.
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1.6
Consequently, the scope of this paper is limited to extractive activities
relating to minerals, oil and natural gas. This represents a change from
IFRS 6 Exploration for and Evaluation of Mineral Resources, which includes
minerals, oil, natural gas and similar non-regenerative resources within
its scope. References to similar non-regenerative resources are also
present in the scope exclusions in IAS 16 Property, Plant and Equipment and
IAS 38 Intangible Assets. The project team notes that, although outside the
research scope, the proposals in this paper might provide insights into
possible future accounting and disclosure models for other
non-regenerative resources and activities with similar risks and
uncertainties.
Research parameters
1.7
Research into the financial reporting issues relating to extractive
activities has been subject to the following parameters.
Common requirements across the minerals and oil and gas
industries
1.8
A research objective was to consider whether common requirements
could be applied to minerals and oil and gas extractive activities. If so,
this would be a change from existing practices, whereby the accounting
and disclosure approaches often differ between entities operating in the
minerals and oil and gas industries. Differences in the accounting and
disclosure requirements may reflect the traditionally held view that they
are separate and distinct industries. For instance, the different physical
attributes of minerals and of oil and gas (ie solids versus liquids) affect the
estimation process, and this has influenced the development of different
reserve and resource definitions in each industry.
1.9
However, the main business activities (exploration, evaluation,
development and production) and the geological and other risks and
uncertainties are very similar. In fact, the traditional differences between
the two industries are being reduced as a result of the lead times involved
in moving to production and the ratio of development-to-exploration
expenditures becoming more comparable as oil and gas exploration
moves from onshore conventional oil and gas to more capital-intensive
offshore oil and gas and non-conventional oil and gas (eg oil sands).
The cash flow profile and risks and uncertainties of a non-conventional
oil project may be closer to those for a minerals project than for a
conventional oil and gas project.
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DISCUSSION PAPER MARCH 2010
1.10
Despite the differences between minerals and oil and gas extractive
activities, they are sufficiently similar for a single accounting standard to
apply in the same way as other accounting standards are used by multiple
industries with a variety of circumstances. The project team was
encouraged in this view by the analysis of reserve and resource
definitions by the Committee for Mineral Reserves International
Reporting Standards (CRIRSCO) and the Society of Petroleum Engineers
Oil and Gas Reserves Committee (SPE OGRC). This analysis showed
substantive equivalence between the two sets of industry definitions even
though there are some differences in terminology (see Chapter 2).
1.11
A consequence of adopting ‘extractive activities’ as the scope of an IFRS is
that, in the project team’s opinion, industry debates about whether
particular non-conventional reserves and resources should be classified
as minerals or as oil and gas become largely irrelevant. This is because, as
explained later in the paper, the same accounting requirements and
substantially the same disclosure requirements would apply regardless of
whether, for example, the mining of bitumen, oil shale or coal for the
purposes of generating synthetic oil or gas is classified as mineral or as oil
and gas reserves and resources.
Avoid issues of general application
1.12
Although extractive activities may be regarded as sufficiently different
from other activities to require addressing in a separate IFRS, many other
financial reporting issues for entities in the extractive industries are not
significantly different from those in other industries. Examples are
accounting for inventory, revenue, decommissioning and restoration
liabilities and joint arrangements. Existing IFRSs and standard-setting
projects address these issues and consequently this paper does not
address them. For similar reasons, the paper also does not address
financial reporting issues relating to downstream activities, such as the
refining, processing, marketing and distribution of minerals or oil and
gas other than the refining or processing that is necessary to make the
extracted minerals or oil and gas capable of being sold.
The Framework
1.13
The research presented in this paper has been undertaken in the context of
the Framework for the Preparation and Presentation of Financial Statements, on the
basis that an IFRS for extractive activities should be based on, and be
consistent with, the Framework. However, the project team’s research has
not been constrained to considering only the application of existing IFRSs
to extractive activities. In particular the proposals on recognition in this
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paper may be viewed as inconsistent with the requirements of IAS 38
regarding intangible assets, such as those for research and development
activities.
Scope of financial reporting
1.14
It is not possible, nor is it intended, that financial reporting would meet
all the information needs of users of financial reports. Although there is
no clear definition of what is within the scope of financial reports, this
should become clearer as the IASB’s work continues on the conceptual
framework and management commentary projects. (The scope of
financial reporting as it relates to the project team’s recommended
disclosures is discussed further in Chapter 5.) For the purposes of this
paper, the project team proposes that financial reporting should include
financial information that:
(a)
helps users of financial reports to make decisions;
(b)
can reasonably be viewed as being within the scope of a complete
set of financial statements; and
(c)
meets a cost-benefit test.
Financial reporting issues
1.15
It is generally acknowledged that the most important information about
an entity conducting extractive activities is information about the
minerals or oil and gas reserves and resources under that entity’s control.
Economic decisions that involve investing in, and supplying and lending
to, entities conducting extractive activities are dependent on an
understanding of the quantity and quality of reserves and resources
under the control of the entity. It is the extraction of those reserves and
resources that provides the basis for the economic benefits flowing from
extractive activities.
1.16
The financial reporting issues that are relevant to extractive activities
therefore involve determining:
(a)
definitions of reserves and resources for use in the accounting for,
and disclosure of, extractive activities;
(b)
the assets related to extractive activities that should be recognised
in financial statements and when they should be recognised;
(c)
how those assets should be measured on initial recognition—
alternatives include the historical cost of acquisition or discovery
and fair value or some other current value basis;
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(d)
how those assets should be measured in reporting periods after
initial recognition, including issues such as remeasurement,
impairment and depreciation; and
(e)
the information about extractive activities, including reserves and
resources information, that should be disclosed in financial
statements.
1.17
This paper addresses each of these issues.
1.18
For the purposes of this discussion paper, the assets related to extractive
activities are collectively referred to as ‘minerals or oil and gas properties’
unless otherwise indicated. As Chapter 3 explains, these assets include
the legal rights either to explore for minerals or oil and gas in a specified
location or to extract minerals or oil and gas from that location (ie the
property) as well as information about the property and any plant and
equipment that is not recognised separately.
Users’ needs
1.19
The objective of a general purpose financial report—and therefore of an
IFRS for extractive activities—is to address users’ needs by providing
financial information that is useful for making economic decisions.
1.20
A general purpose financial report is directed towards the common
financial information needs of a wide variety of users. It is unlikely that
the different users of the financial statements of entities in the extractive
industries all share the same view of the information that would be most
useful to them. In particular it is likely that users that are more
sophisticated will have different information needs, and will use
information differently, from less sophisticated users. This is particularly
true when the information concerns complex topics such as estimating
quantities of minerals or oil and gas reserves and resources and the value
attributable to those reserves and resources—a value that will be the
critical factor in economic decisions, such as whether to invest in an
entity or to lend money or extend credit to it.
1.21
The needs of more sophisticated users are often the focus of
standard-setters for the following reasons.
(a)
Many less sophisticated users rely on the analysis of more
sophisticated users. This is true of individual investors who use
professional financial advisers as well as businesses that use the
services of credit-rating agencies.
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(b)
The information needs of more sophisticated users are generally
more extensive and detailed than those of less sophisticated users.
Meeting the needs of the more sophisticated users should meet the
needs of the less sophisticated users.
(c)
It is generally easier to get input from more sophisticated users
about their needs.
1.22
As part of the research for this discussion paper, detailed individual
interviews were held with 34 professional users around the world who
focus on entities in the extractive industries. These users comprised
buy-side analysts, sell-side analysts, venture capitalists, lenders and
debt-rating agencies. The survey focused on information about minerals
or oil and gas reserves and resources, and not on other information in the
financial statements such as cash flow, debt and exploration
expenditures. (More detail on the process used is provided in Appendix C.)
1.23
The main survey findings from the users interviewed are as follows:
(a)
The historical cost information on minerals or oil and gas
properties in the statement of financial position does not generate
useful information. This is true whether the accounting method is
full cost, successful efforts or area of interest. The accumulated
costs incurred to find a deposit of minerals or oil and gas are not
useful in predicting the future cash flows from that property.
However, some historical cost information is useful. For example,
the finding costs per unit of oil reserves found is useful in
evaluating the entity’s ability to find oil reserves efficiently. This
information depends on expenditure data rather than on data in
the statement of financial position that include expenditures
capitalised (but not those recognised as expenses) over many years,
and are net of depreciation and impairment.
(b)
Recording minerals or oil and gas properties at fair value in the
statement of financial position would not generate useful
information. This response was not expected, as the value of
properties, and particularly the estimates of the underlying
reserves and resources, is important information for users in
making economic decisions. These users explained that there are
many significant variables that go into a valuation and there can
be substantial subjectivity involved. They consider it important to
apply their own judgement to those factors rather than relying on
management’s judgement, and they undertake extensive research
in order to do this. As professional users, their judgement and
insights are important in determining their valuation of an entity
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and of its minerals or oil and gas properties. Concerns were also
expressed about possible bias in fair values of minerals or oil and
gas properties prepared by the entity given the extent of judgement
that has to be applied. Most users interviewed said they would not
rely on a fair value provided by the entity unless there was
extensive disclosure of the assumptions used. Such disclosure
would allow users to decide if they agreed with the assumptions,
and only in that case would they use the fair value provided. Given
the number of assumptions within a fair value estimate, most users
thought that it would be unlikely that the fair value would be
particularly useful. Some users said they might use a fair value
estimate provided by the entity’s management to check their own
estimate. Users would, in effect, try to reconcile their estimate to
management’s fair value to make sure they understood the
difference.
This would also provide some insight into
management’s expectations for the future.
*
(c)
Users generally did not consider that a valuation prepared using
specified inputs (such as price) would provide useful information.
An example of this type of valuation is the standardised measure
required for oil and gas reserves by the US Financial Accounting
Standards Board (FASB) Accounting Standards Codification™ (ASC)
section 932-235-50.* This measure is based on proved reserves,
year-end prices and costs, and a 10 per cent discount rate. Users
explained that such mandated values for the main variables are
unlikely to be consistent with their views of the inputs relevant to
the determination of value. However, some users of the financial
statements of oil and gas entities find the standardised measure
disclosures useful—primarily the disclosure of the main
components of the measurement and the year-on-year analysis of
the changes in the measure rather than in the measure itself.
(This is discussed further in Chapter 5.)
(d)
Users are looking for information, either within the financial
statements or elsewhere, that will be useful in estimating the value
of the entity. For an entity in the extractive industries this usually
means information about the reserves and resources. Much of the
information will be the same whether the user is looking at a
minerals entity or an oil and gas entity—for example, information
on the quantities of reserves, development and production costs
and how those reserve estimates and cost bases change over time.
This disclosure requirement was introduced into US generally accepted accounting
principles (GAAP) by SFAS 69 Disclosures about Oil and Gas Producing Activities.
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However, some of the information will differ according to the type
of mineral or oil and gas—for example, information on by-products
and the grades of the minerals.
1.24
These findings from the user survey have been considered by the project
team in determining its views on asset recognition and measurement,
and on the disclosure of information about an entity’s minerals and oil
and gas properties.
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Chapter 2 – Definitions of reserves and resources
Introduction
2.1
Reserves and resources are either the most significant assets or amongst
the most significant assets for most entities engaged in extractive
activities. Assessing the financial position and performance of an entity
engaged in extractive activities in order to make economic decisions
therefore requires an understanding of the entity’s minerals or oil and
gas reserves and resources, which are the source of future cash flows. This
chapter considers the definitions of reserves and resources that should be
used in financial reporting in order to facilitate this assessment.
Subsequent chapters of this discussion paper consider how reserve and
resource information should be reflected in the financial statements and
in the notes.
Reserves and resources
2.2
Broadly speaking, the underlying purpose of reserve and resource
definitions is to communicate information about the quantity of
minerals or oil and gas that is estimated to exist in a deposit and may be
recoverable.* However, identifying the definitions of reserves and
resources that should apply in the financial reporting of minerals and oil
and gas extractive activities is not straightforward, primarily because
there is no single, generally accepted definition of reserves and resources
that applies both to minerals and to oil and gas.
2.3
Most definitions of reserves and resources share similar nomenclature
and basic concepts. This is because these definitions mainly derive from
a system recommended by VE McKelvey of the United States Geological
Survey in the early 1970s (and commonly referred to as the ‘McKelvey box’
diagram).
2.4
The basic concepts of a ‘reserve’ and a ‘resource’ are as follows:
(a)
*
Reserves generally refer to the quantity of minerals or oil and gas that
is estimated to be economically recoverable from the earth. In other
words, reserve quantities are an estimate of the aggregate future
production of minerals or oil and gas.
In the minerals industry, reserves and resources are usually quantified in terms of
tonnages. In the oil and gas industry, reserves and resources are usually expressed in
terms of volumes and quantified as barrels of oil or cubic feet of gas.
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(b)
(c)
2.5
*
Resources generally refer to the quantity of minerals or oil and gas
that has been discovered but is not yet capable of being classified as
a reserve.* This may be because:
(i)
insufficient drilling, analysis and planning have been
undertaken to indicate whether the minerals or oil and gas
may be economically recoverable;
(ii)
the minerals or oil and gas are not expected to be
economically
recoverable
under
current
economic
conditions, but there are reasonable prospects for such
economic conditions to change and thereby allow for
eventual economic extraction; or
(iii)
development and production of the minerals or oil and gas
deposit are contingent on other factors that may prevent
timely development of the property, such as the need to
develop a market for the production or to respond to
environmental concerns.
Reserves and resources are generally classified into subcategories
according to the level of confidence associated with the estimate of
the reserve or resource quantities.
The major differences in the various definitions of reserves and resources
relate to the scope and specificity of the definitions and also to the
assumptions that are to be used in estimating and classifying reserves
and resources. These differences in the detail of the definitions can be
explained (at least in part) by two factors. First, although many of the
definitions of mineral reserves and resources and oil and gas reserves and
resources have common roots in the McKelvey box diagram, they have
subsequently evolved largely independently of each other. This is not
surprising given the different physical properties of minerals (solid) and
oil and gas (typically fluid) and the fact that the minerals and oil and gas
industries are typically regarded and organised as separate and distinct
industries. Secondly, definitions of reserves and resources have been
developed by various organisations around the world, such as industry
and professional associations, securities regulators and other
government and international agencies. In some cases, the definitions
differ because they were developed to meet different information needs.
For instance, for some commodities, there are differences in the
definitions of reserves and resources used to report information on
Particularly in the oil and gas industry, the term ‘resources’ can also be used to refer to
quantities that have not yet been discovered.
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reserves (and sometimes resources) to investors, to the entity’s
management, and to governmental or international agencies for natural
resource management purposes. In other cases, the definitions of
reserves and resources differ between jurisdictions even though they are
intended to meet the same information needs (eg to report reserve and
resource information to investors).
2.6
Consequently, the definition of a ‘reserve’ and a ‘resource’ (or similar terms)
can vary depending on the industry, the jurisdiction and the reason for
preparing the estimate. This diversity in definitions can make it difficult to
compare the reserve and resource information that has been reported by
different entities. This is not helpful to users of financial reports.
Financial reporting needs
2.7
2.8
In defining reserves and resources in an IFRS for extractive activities, the
project team considers that:
(a)
consistent definitions of minerals and oil and gas reserves and
resources should be used; and
(b)
these definitions should be compatible with financial reporting
methodologies and requirements.
Consistent definitions of minerals and oil and gas reserves and resources
are needed as part of developing accounting and disclosure requirements
that are comparable within and across the two industries. As noted in
Chapter 1, this is one of the research project’s objectives.
Alternatives for defining reserves and resources
Developing new definitions
2.9
One alternative that would enable the use of consistent definitions of
minerals and oil and gas reserves and resources in IFRSs is to develop a
new set of reserves and resources definitions that could apply equally to
minerals and to oil and gas. Developing new definitions poses several
challenges. First, the IASB does not have the requisite technical expertise
in geology and engineering disciplines to be able to develop a
comprehensive set of reserve and resource definitions (and
accompanying guidance). It would therefore need either to seek to have
another entity develop the definitions or to acquire the necessary
expertise. If the IASB itself were to develop new definitions, it would be
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custodian of the definitions. The IASB would be responsible for their
continuing maintenance to ensure the definitions kept pace with
changes in knowledge, technology and best practices. Having definitions
for financial reporting purposes that are different from those used by
geologists and an entity’s management also has obvious disadvantages in
that it would be likely to result in confusion and a lack of understanding
of the definitions. For these reasons the project team decided that other
options should be considered.
Consistent definitions
2.10
The alternative to developing a new set of definitions of minerals and oil
and gas reserves and resources is to identify whether there are suitable
existing reserve and resource definitions in each industry. These
definitions would need to be sufficiently consistent (but not necessarily
identical) definitions that would be suitable for developing common
accounting and disclosure requirements across the minerals and oil and
gas industries. The definitions are considered to be consistent if:
(a)
the terminology is generally consistent;
(b)
where consistent terminology cannot be used, there is a one-to-one
relationship between terms used in minerals and in oil and gas;
and
(c)
the terminology has essentially the same meaning, even if different
words are used.
This approach is pragmatic. It avoids the difficulties of the IASB
developing its own definitions for accounting purposes—but it requires
some deviation from a single set of definitions. The approach also
depends on the co-operation of the sponsors of the definitions.
The research project has focused on this alternative.
Existing reserves and resources definitions
2.11
Internationally, the most prominent definitions of minerals and oil and
gas reserves and resources being used for financial reporting and other
public reporting purposes are:
(a)
mineral reserve and resource definitions based on the Committee
for Mineral Reserves International Reporting Standards (CRIRSCO)
International Reporting Template for the Public Reporting of Exploration
Results, Minerals Resources and Mineral Reserves.
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(b)
the Petroleum Resource Management System sponsored by the Society of
Petroleum Engineers (SPE), the World Petroleum Council (WPC),
the American Association of Petroleum Geologists (AAPG), and the
Society of Petroleum Evaluation Engineers (SPEE).*
(c)
the definitions established by the US Securities and Exchange
Commission (SEC), which are located in:
(i)
Regulation S-X, Rule 4-10 Financial accounting and reporting for oil
and gas producing activities pursuant to the Federal Securities Laws
and the Energy Policy and Conservation Act of 1975; and
(ii)
SEC Industry Guide 7—Description of Property by Issuers Engaged or
to Be Engaged in Significant Mining Operations.
2.12
Another classification system for reserves and resources is the United
Nations Framework Classification for Fossil Energy and Mineral Resources (UNFC).
The UNFC is a joint initiative incorporating the professional efforts of
CRIRSCO, SPE/WPC/AAPG/SPEE and others with strong stakeholder
participation. The UNFC is seeking to harmonise the classification of
reserves and resources to meet four defined information needs—being
financial reporting, business process management, government resource
management and global energy (and mineral) studies.
2.13
An overview of each of these sets of minerals or oil and gas definitions is
provided in Appendix B.
Comparison study
2.14
*
Following a request from the IASB as part of the research project, an
expert industry working group comprising members of the CRIRSCO and
the SPE Oil and Gas Reserves Committee undertook a detailed review of
their respective reserve and resource definitions (a) to identify the
potential for greater convergence of the definitions and (b) to consider
alternative approaches that might promote a common understanding of
minerals and oil and gas reserve and resource definitions.
In a survey of oil and gas entities that prepare consolidated financial statements in
accordance with IFRSs, KPMG found that of the 29 entities that presented a reserves
report, ten entities prepared reserves disclosures in accordance with the SEC rules and
SFAS 69, four entities used the SPE definitions (which are now known as the PRMS), two
entities followed the Statement of Recommended Practice Accounting for Oil and Gas
Exploration, Development, Production and Decommissioning Activities issued by the UK Oil
Industry Accounting Committee and one entity used the requirements published by the
UK Listing Authority. The remaining twelve entities did not identify the definitions
they had used. See KPMG, The Application of IFRS: Oil and Gas (October 2008), page 69.
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Representatives from the International Organization of Securities
Commissions and the United Nations Economic Commission for Europe,
which sponsors the UNFC, also monitored the review and provided
feedback as it progressed.
2.15
The focus of the research on the reserve and resource definitions in the
CRIRSCO Template and in the PRMS reflects the fact that both are widely
accepted and have a broad and comprehensive scope. The reasons why
the research placed less focus on the SEC definitions and the UNFC is
explained in paragraphs 2.18–2.23 below.
Wide acceptance
2.16
The CRIRSCO Template and the PRMS are widely accepted, as shown by
the fact that both sets of definitions usually form the basis of the reserve
and resource estimates that are disclosed to investors and/or are reported
to the entity’s internal management. Specifically:
(a)
the CRIRSCO Template is regarded as the dominant international
classification system for mineral reserves and resources, with the
national reporting codes (mentioned in Appendix B) forming the
basis of market regulator disclosure requirements in most
jurisdictions that have formalised mineral reserve and/or resource
disclosure requirements (excluding the US SEC).
(b)
the PRMS is regarded as the dominant international classification
system for oil and gas reserves and resources, primarily because of its
use in internal resource management by many oil and gas entities.
The PRMS also corresponds closely to market regulator disclosure
requirements in most jurisdictions that have formalised oil and gas
reserve and/or resource disclosure requirements (including Canada
and the US SEC following the 2008 revisions to its oil and gas reserve
definitions—see paragraph 2.18 for further details).
A broad and comprehensive scope
2.17
Both the CRIRSCO Template and the PRMS are comprehensive
classification systems that also have a broad scope in terms of coverage of
types of minerals and oil and gas. A broad and comprehensive scope is
important for the design of comprehensive accounting and disclosure
requirements for entities engaged in extractive activities. The CRIRSCO
Template includes all solid minerals, including diamonds, other
gemstones, industrial minerals, stone and aggregates, and coal. The
PRMS includes all types of ‘conventional’ and ‘unconventional’
petroleum, and therefore includes, among other things, crude oil,
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natural gas, coalbed methane, natural bitumen (tar sands) and oil shale
deposits. The definitions are also comprehensive, insofar as they both
provide classifications for quantities of minerals or oil and gas that, as a
minimum, are expected to have reasonable prospects for eventual
economic extraction.
SEC definitions
2.18
2.19
The SEC’s definitions of minerals and oil and gas reserves are also
commonly used for financial reporting purposes. The scope of the
comparison study did not extend to identifying the degree of
comparability between the SEC definitions because, at the time the study
was undertaken, the following reasons were considered to diminish the
suitability of the SEC definitions for use in an eventual IFRS for extractive
activities.
(a)
The scope of the SEC definitions was limited to proved reserves for
oil and gas (it is now limited to proved, probable and possible
reserves) and to proved reserves and probable reserves for minerals.
The limited scope of these definitions would constrain the ability
of an IFRS to provide users of financial reports with useful
information, given that some of the responses to the user survey
suggested that the disclosure of probable oil and gas reserves and
the disclosure of mineral resources can provide useful information.
(b)
Many industry commentators have suggested that the minerals
definitions and the oil and gas definitions (until revised in
December 2008) have not kept pace with industry developments
and generally accepted current practices for reserve and resource
assessment. Consequently, reserve and resource information
prepared in accordance with those definitions may not be
representative of the assumptions that market participants would
use, and it might not reflect the reserve and resource position of
the entity as seen through the eyes of its management.
The SEC’s release of its revisions to its definitions of oil and gas reserves
has not changed the project team’s view that the PRMS and the CRIRSCO
Template definitions are the definitions that should be assessed for
comparability. Even though the revised SEC oil and gas definitions are
broadly comparable to the PRMS, the project team regards the PRMS as
more suitable for use in financial reporting because it offers a more
complete classification system as a result of its comprehensive
classification of resources. Similarly, the project team regards the
CRIRSCO Template as more suitable for use in financial reporting because
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the SEC minerals definitions do not include resource classifications and
because some in the minerals industry have expressed concern that those
definitions may not be consistent with current industry practices.
2.20
Some oil and gas industry participants have suggested that the PRMS’s
reserves definitions are less prescriptive than the corresponding revised
SEC reserves definitions and the Canadian Securities Administrators’
National Instrument 51–101 reserves definitions. They believe there may
be less consistency between reserves estimates prepared under the PRMS
compared to estimates prepared under either the SEC or the Canadian
definitions and that this outcome may not be compatible with setting
financial reporting standards. The project team does not think that this
concern should lead to the adoption of definitions other than the PRMS
or, for that matter, the CRIRSCO Template. The PRMS and the CRIRSCO
Template are principle-based classification systems and rely on reserves
estimators to use their professional judgement rather than provide
prescriptive application guidance. The project team’s view is that, to the
extent that there is unacceptable diversity in the application of a
principle within the PRMS or the CRIRSCO Template, the diversity should
be resolved by an amendment to the PRMS or the CRIRSCO Template
rather than by developing a separate set of definitions (as discussed in
paragraph 2.9) or by adopting existing minerals definitions and oil and
gas definitions that may not be comparable.
The UNFC
2.21
The UNFC has a broad scope and is the only internationally recognised
system that is known to have been applied to both solid minerals and oil
and gas (eg for all reserves and resources in Ukraine). However, the UNFC
has not been used for financial reporting purposes and, as noted in
Appendix B, the detailed formulation of the UNFC is being further
developed.
2.22
The project team therefore thinks that, at this time, the UNFC is not an
alternative to the CRIRSCO Template and PRMS definitions for the
purposes of establishing financial reporting requirements in an IFRS for
extractive activities. A universally applicable classification system would
meet the research project’s objective of consistent definitions of minerals
and oil and gas reserves and resources, but the project team considers
that before it could be used within IFRSs it would need to be
demonstrated that the UNFC:
(a)
can be consistently applied and independently verified for the
purposes of disclosing reserve and resource information to capital
market participants; and
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(b)
2.23
is accepted for use by the minerals and oil and gas entities that are
preparing the disclosures to the capital markets and by the analysts
and other financial reporting users in making their investment
decisions.
The project team recommends that further consideration should be given
to the progress made on the UNFC if and when an extractive activities
project is added to the IASB’s active agenda.
Comparison study findings
2.24
In comparing the CRIRSCO Template and the PRMS, the expert industry
working group found that ‘there is a high degree of compatibility in the
classification logic that petroleum and minerals evaluators apply in
determining quantities of their respective materials that reside in a field
or a deposit and can be extracted and marketed’.*
2.25
The expert industry working group recommended that the alignment
between the CRIRSCO Template and PRMS reserve and resource
classification systems should be communicated by ‘mapping’ the
classification systems and terminology rather than through amending
the reserve and resource definitions directly to achieve common
definitions of reserves and resources across the minerals and oil and gas
industries. The working group concluded that it is not practical to seek to
create a common set of definitions of minerals and oil and gas reserves
and resources for a variety of technical and historical reasons.
The working group explained that each industry has developed separate
classification and categorisation logic and, in many cases, the logic is
related to the physical in situ differences in the material, the assessment
techniques, and the appropriate extraction and processing methods.†
They also noted that moving to a common set of definitions would be
extremely difficult given the long history of each industry, wherein these
terms and approaches have become embedded in practice and, in some
cases, in legal documents.§
2.26
The report produced by the expert industry working group in September
2007, which includes a comprehensive comparison of the classification
and terminology in the PRMS and the CRIRSCO Template, is Mapping of
*
CRIRSCO and SPE OGRC, Mapping of Petroleum and Minerals Reserves and Resources
Classification Systems (the Mapping Report), September 2007, page 10
†
Mapping Report, page 10
§
Mapping Report, page 3
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Petroleum and Minerals Reserves and Resources Classification Systems. It is
available from the extractive activities research project page on the IASB
website (www.iasb.org).
Comparable concepts
2.27
The expert industry working group found that in comparing the PRMS
and the CRIRSCO Template reserve and resource classifications:
(a)
there is broad equivalence between the mineral reserve and
(petroleum) reserve classifications;
(b)
the classifications of proved and probable reserves in each
classification system have the same general level of confidence in
the quantity of recoverable minerals or oil and gas; and
(c)
there is broad equivalence between the mineral resource and
(petroleum) marginal contingent resource classifications.
Each of these comparable concepts is discussed further in the next section.
2.28
Figure 2.1 below illustrates how the PRMS and CRIRSCO Template reserve
and resource classifications compare.*
Figure 2.1: Mapping of the PRMS and the CRIRSCO Template
Petroleum (SPE/WPC/AAPG/SPEE 2007)
Minerals
2P
Probable
Possible
3P
Proved
developed
Increasing Commercial Certainty
CONTINGENT
RESOURCES
2C
1C
3C
Potentially
Commercial
PROSPECTIVE
RESOURCES
Low
Estimate
Best
Estimate
Probable
MINERAL RESOURCES
Measured
Inferred
Indicated
Discovered Not Economic
EXPLORATION RESULTS
High
Estimate
UNRECOVERABLE
Range of Technical Uncertainty
Not to scale
*
the Modifying Factors
1P
undeveloped
Proved
marginal
Commercial
MINERAL RESERVES
RESERVES
sub -marginal
DISCOVERED IIP
Sub -Commercial
P10
P50
P90
(CRIRSCO 2006)
PRODUCTION
UNRECOVERABLE
UNDISCOVERED IIP
TOTAL PETROLEUM INITIALLY -IN-PLACE (IIP)
PRODUCTION
Increasing level of geoscientific
knowledge and confidence
This diagram, which is included in the Mapping Report (see figure 4), is based on a draft
depiction of the PRMS. The depiction of the PRMS in Petroleum Resource Management
System (2007) is presented at figure 1-1 of that document.
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Reserves
2.29
Both the CRIRSCO Template and the PRMS regard reserves as being
quantities of minerals or oil and gas that are:
(a)
discovered;
(b)
available for extraction (ie not already extracted);
(c)
recoverable, meaning that the technology is available and validated
to extract the useful mineral from the ground and by subsequent
processing, where necessary, to yield a marketable product; and
(d)
economic, meaning that development and production of the mine
or field can be justified.
Comparing the meaning of ‘economic’ and ‘commercial’
2.30
2.31
The CRIRSCO Template requires that reserves be ‘economically mineable’;
the PRMS states that reserves are anticipated to be ‘commercially
recoverable’. Both concepts are used to indicate that development and
production of the mine or field can be justified, as a result of the project
being expected:
(a)
to generate a positive net present value at a defined discount rate.
This discount rate will typically represent the ‘hurdle rate’ that
must be earned in order for the entity to justify its investment in
the project.
(b)
to satisfy all of the modifying factors (as referred to in the CRIRSCO
Template) or contingencies (as referred to in the PRMS) that may
exist and affect the project throughout its life. The evaluation of
these modifying factors/contingencies, which include economic,
marketing, legal, environmental, social and governmental factors,
is undertaken when preparing project development plans such as
feasibility studies or development planning studies. To satisfy the
reserves classification, the outcome of this evaluation should
indicate that implementation of the development and production
plans can proceed (or should not be prevented).
In addition, to be commercially recoverable and recognised as a reserve,
the PRMS requires that there must be a commitment to initiate
development within a reasonable time frame, noting that five years is
recommended as a benchmark. The classification generally reverts to
marginal contingent resources if development is no longer expected to
take place within this time frame, which may be as a result of the effect
of the contingencies or because of the entity’s own internal prioritisation
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of projects. The PRMS allows the reserves classification to be retained
when there are delays significantly longer than five years, but these cases
and the rationale for retaining the reserves classification must be clearly
documented.
2.32
A similar demonstration of the entity’s intention to develop is not
explicit within the CRIRSCO Template, because the completion of
feasibility studies does not require a decision to mine. Although this
represents a theoretical difference between what is ‘economic’ and
‘commercial’, the expert industry working group concluded that the
practical application of these concepts provides for a comparable
outcome. This is because the group noted that any feasibility study that
has not been implemented within five years would require a
reassessment of feasibility, and quantities would either be retained as
mineral reserves, ‘refreshed’ on an annual basis, or downgraded to
mineral resources as a result of that reassessment.
Comparing economic assumptions
2.33
Determining whether a project will be economic requires estimating the
future cash flows associated with the development and production of a
mine or field. Some components of the future cash flow estimates will be
based primarily on project-specific factors, such as the timing of future
cash flows and the production quantities. Other components of the
estimate will be more directly influenced by external financial
conditions, including commodity prices, costs of labour, materials and
equipment, foreign exchange rates and discount rates. Both the CRIRSCO
Template and the PRMS indicate that the financial assumptions used in
the reserves estimates should be the entity’s internal forecasts of future
conditions that will exist over the life of the project, on the proviso that
these assumptions are realistically assumed (as referred to in the
CRIRSCO Template) or reasonable (as referred to in the PRMS).
2.34
The PRMS acknowledges that alternative economic scenarios may be
incorporated into reserves reporting, such as a current economic
conditions scenario using historical oil and gas prices and associated
costs, possibly over a defined averaging period. The PRMS suggests that a
one-year historical average of costs and prices should be used as the
default basis for defining current conditions. The PRMS acknowledges
that regulatory agencies may choose to apply alternative definitions for
these conditions for the purposes of external disclosure.
2.35
The CRIRSCO Template does not contemplate the use of financial
assumptions other than the entity’s internal forecasts.
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Proved and probable reserves
2.36
The expert industry working group found that the classifications of
proved and probable mineral reserves under the CRIRSCO Template have
the same general level of associated confidence as proved and probable
petroleum reserves under the PRMS. Furthermore, the group noted that
the sum of proved plus probable reserves is the evaluator’s best estimate
of the remaining recoverable quantities of minerals or oil and gas based
on the information available at the time the estimate is made.
2.37
Although not affecting the overall conclusion, the presentation basis for
proved and probable reserves for minerals and for oil and gas are
different in that:
(a)
under the CRIRSCO Template, probable reserves are an incremental
estimate of recoverable quantities of minerals above and beyond
the quantities that are classified as proved reserves; and
(b)
under the PRMS, probable reserves are often reported as part of a
cumulative reserves (2P) estimate that also includes proved
reserves.
2.38
Reporting reserves (and resources) estimates for minerals on an
incremental basis and for oil and gas on a cumulative basis is consistent
with the different physical properties of minerals and oil and gas and the
resulting different methods used to estimate reserves. Because minerals
are solids, extensive drilling of a minerals deposit is generally required to
estimate the size of the deposit and the variability of the grade of the
minerals present. The reserves estimate is constructed on a local scale,
meaning that the confidence assigned to the portions of the deposit is
based on the distance between drill holes and also influenced by other
factors including whether the mineralisation is uniform (eg for many
coal deposits) or erratic (eg for nuggetty gold deposits).
2.39
In contrast, with most oil and gas deposits, the oil and gas can flow
towards an extraction well. Less drilling is therefore necessary to
estimate the size of the reservoir and the flow rates of the oil and gas
(reservoir pressure). Probability distributions can be used to estimate oil
and gas reserves, and as a consequence reporting a cumulative reserves
estimate is consistent with this estimation approach. In short, a 2P, or
P50, reserves estimate (as shown in figure 2.1) equals the sum of proved
plus probable reserves. The PRMS also allows reserves to be estimated
using a deterministic method (ie qualitative thresholds, such as high
confidence estimate and best estimate), which is the same basis applied
under the CRIRSCO Template.
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Resources
2.40
The expert industry working group concluded that mineral resources are
essentially the same as marginal contingent resources in the PRMS in that
they are contingent on further events or actions before they can be
converted into reserves. This may simply mean that feasibility or other
studies have not been undertaken or completed, or it may mean that
economic conditions have to change to some extent to enable the
resources to be reclassified as reserves. In general, there will be a realistic
expectation that these conditions will eventually be met.
Differing concepts
2.41
The major differences between the PRMS and CRIRSCO classifications are
also evident from figure 2.1 above—being the absence from the CRIRSCO
Template of classifications that are equivalent to ‘possible reserves’ and
‘sub-marginal contingent resources’.
2.42
Possible reserves represent the potential upside relating to proved and
probable oil and gas reserves. The nearest equivalent to possible reserves
in the CRIRSCO Template is inferred resources. The project team
considers these categories of reserves and resources sufficiently
uncertain that they would not materially affect decisions on asset
recognition and measurement or be the primary focus of disclosure.
For this reason, direct comparability between the CRIRSCO Template and
the PRMS in this classification is not considered essential for financial
reporting purposes.
2.43
The report prepared by the expert industry working group explains that
‘Sub-Marginal Contingent Resources are those quantities associated with
discoveries for which analysis indicates that technically feasible
development projects would not be economic and/or other contingencies
would not be satisfied under current or reasonably forecasted
improvements in commercial conditions. These projects nonetheless
should be retained in the inventory of discovered resources pending
unforeseen major changes in commercial conditions.’* In contrast, the
CRIRSCO Template does not have a comparable classification because its
scope does not include the reporting of mineralisation that does not have
reasonable prospects for eventual economic extraction, even though it
may be discovered. The project team considers that if a minerals or oil
and gas discovery is not considered to have reasonable prospects for
eventual economic extraction, the disclosure of this resources
*
Mapping Report, page 5
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DISCUSSION PAPER MARCH 2010
classification is unlikely to provide useful information or to materially
affect the recognition and measurement of the asset in the statement of
financial position.
2.44
2.45
Other differences that have been identified between the PRMS and the
CRIRSCO Template classifications relate to how the estimate is quantified
and presented.
(a)
The measurement of reserves and resources under the PRMS is
presented in terms of the ‘sales quantity’ delivered at a custody
transfer point according to product delivery specifications,
whereas under the CRIRSCO Template, the measurement is
presented in terms of tonnage of ore and mineral grade (ie the
percentage of the contained mineral). The CRIRSCO Template then
requires disclosure of recovery factors that enable the ‘sales
quantities’ to be computed. Some entities also disclose the sale
quantities of product in addition to disclosing quantities in terms
of tonnes and grade.
(b)
In terms of an entity’s interest in reserves and resources, oil and gas
reserves and resources estimates are typically expressed on a net
working interest or net entitlement basis after reduction for
royalties and production owing to others. However, mineral
reserve and resource estimates are typically reported in total with
the share attributable to the entity shown separately.*
These differences, however, do not make the reserve and resource
classifications incompatible. Rather, the differences are a disclosure
issue, and are related to how minerals and oil and gas reserve and
resource disclosures are typically presented. The disclosure of minerals
and oil and gas reserve and resource information is considered in
Chapter 5 of this discussion paper.
Comparability of definitions to accounting principles
2.46
For the purposes of reporting on the financial position and performance
of an entity in the financial statements, the definitions of reserves and
resources can be useful for:
(a)
*
the measurement of the minerals or oil and gas property (eg if the
property is measured at current value; in a business combination
or impairment assessment if the property is measured at historical
cost); and
Mapping Report, page 8, items 3 and 8
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(b)
the expected lives of mines or oil and gas fields, which influence
the calculation of:
(i)
depreciation for assets that have the same useful lives as a
mine or field; and
(ii)
rehabilitation liabilities, by outlining when future cash
outflows associated with the rehabilitation are expected to be
made.
2.47
As reserve and resource estimates can therefore influence the calculation
of an entity’s financial performance and position, it follows that the
reserve and resource definitions (and the assumptions underpinning the
estimates) should be compatible with generally accepted accounting
principles. Otherwise, there may not be consistency between the reserve
and resource estimates and the items in the financial statements that
either represent reserves and resources (ie minerals or oil and gas
properties) or are impacted by reserves and resources estimates
(eg restoration liabilities, which are estimated on the basis of the life of
the mine or field). Such an outcome would fail to meet the qualitative
characteristics of useful financial information, as defined by the
Framework.
2.48
In comparing the CRIRSCO Template and PRMS definitions with generally
accepted accounting principles, the project team found two features of
the definitions that could cause reserve and resource estimates to be
prepared on a basis that, in some instances, could be inconsistent with
generally accepted accounting principles. These relate to:
(a)
the economic assumptions that are applied to derive a reserve
estimate; and
(b)
the conditions that must exist before a resource can be converted
into a reserve.
Economic assumptions
2.49
As noted above, the CRIRSCO Template and the PRMS both indicate that
the economic assumptions used in reserves and resources estimation
should be based on the entity’s internal forecasts of future conditions.
The notion of using internal forecasts of economic assumptions in
financial reporting without also having to refer to market-based evidence
is generally not supported in IFRSs, although measuring the recoverable
amount of an asset at its value in use in accordance with IAS 36 Impairment
of Assets involves internal forecasts and segment disclosures in IFRS 8
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Operating Segments are measured at amounts reported to the chief
operating decision maker, and this may include internal assumptions.
2.50
More typically, IFRSs require that estimates should use economic
assumptions that reflect market-based evidence where available.
The proposals in the exposure draft Fair Value Measurement* define fair
value and establish a hierarchy for selecting the most relevant inputs to
be used in estimating fair value for financial reporting purposes. Broadly
speaking, the fair value hierarchy requires market-based assumptions to
be used where possible, and restricts the use of internal forecasts to
situations where market-based assumptions are not available.
The hierarchy prioritises the inputs as follows:
(a)
Level 1 inputs—observable inputs that reflect quoted prices
(unadjusted) for identical assets in active markets that the
reporting entity has the ability to access at the measurement date.
(b)
Level 2 inputs—these include:
(c)
2.51
*
(i)
quoted prices for similar assets in active markets;
(ii)
quoted prices for identical or similar assets in markets that
are not active;
(iii)
inputs other than quoted prices that are observable for the
asset (eg interest rates, yield curves, volatilities that are
observable at the commonly quoted intervals, and default
rates);
(iv)
inputs that are derived principally from or corroborated by
observable market data through correlation or by other
means (market-corroborated inputs).
Level 3 inputs—unobservable inputs, to be used only to the extent
that observable inputs are not available. This allows for situations
where there is little, if any, market activity in respect of the asset at
measurement date.
Although the exposure draft addresses the fair value of an asset, the
project team thinks that the proposed guidance on estimating fair value
is also relevant to estimating quantities of reserves and resources for
financial reporting purposes. In both cases the objective is an unbiased
The IASB published the exposure draft in May 2009. The proposals in the exposure draft
are based on SFAS 157 Fair Value Measurements. The main differences between the
exposure draft and SFAS 157 are identified in paragraph BC110 of the Basis for
Conclusions accompanying the exposure draft.
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measurement of an asset—in one case of quantity and, in the other case,
of value. This unbiased measure is achieved by using, to the extent
possible, market inputs. Both the estimate of reserves and resources
quantities and the estimate of the value of those quantities depend on
similar economic assumptions. Accordingly, in the project team’s
opinion, the economic assumptions used to estimate reserve and
resource quantities should be consistent with those used to estimate the
fair value of the minerals or oil and gas properties.
Applying fair value measurement principles to reserve and
resource estimation
2.52
The following paragraphs consider the application of fair value
measurement principles to the main economic assumptions that are
incorporated into reserve and resource estimation.
Commodity price assumptions
2.53
Commodity price assumptions need to take account of the following
variables:
(a)
the expected prevailing market price for the commodity when it is
produced and is ready for sale (which for some mines and oil and
gas fields may extend well beyond 20 years into the future);
(b)
any pricing differential based on expected quality of the produced
commodity; and
(c)
the location of the commodity.
2.54
Although spot and future prices may be quoted in active markets for
some commodities (ie Level 1 inputs), valuing recoverable quantities of
minerals or oil and gas would need to take into account the variables
above. For this reason, the price assumptions used in measuring fair
value of a mineral or oil and gas property are expected to be based on
Level 2 or Level 3 inputs.
2.55
For some homogeneous commodities, long-term views on commodity
prices might be capable of being either directly observed or extrapolated
and corroborated by other observable market transactions. In those
cases, the price assumptions to be used could be a Level 2 (market-based)
input rather than a Level 3 (entity-specific) input. However, the use of
market-based forecast prices is generally expected to be available only for
those commodities where a futures market exists and then only when the
futures market provides a forecast of spot prices in the future rather than
representing the current spot price plus carrying costs. Futures prices do
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not represent a forecasting tool for commodities that are storable and
where large inventories of that commodity already exist. Economists
have observed that in these situations, arbitrageurs or market
participants with existing inventory will ensure that the difference
between the current spot price and the future price will be the carrying
costs of interest and storage costs that would be incurred until the
maturity of the futures contract. Therefore, whether futures prices
provide a forecast of spot prices in the future will depend on the
characteristics of individual commodities markets. It might mean that
the only observable market participant pricing outlook for many traded
commodities will be the current spot price, although the current spot
price may also be responding to short-term supply and demand factors
rather than to longer-term factors.
2.56
The quality or location of the commodity may have an influence on the
commodity price, which may necessitate adjusting any market-based
long-term view on commodity prices that is capable of being observed or
extrapolated. In those circumstances, factoring the quality and location
of the commodity into a pricing assumption would presumably involve
unobservable market inputs (most likely entity-specific inputs).
Exchange rate assumptions
2.57
Exchange rate assumptions must be made when commodity prices and
capital, operating and refining costs involve more than one currency.
Like commodity prices, some spot and future exchange rates will be
quoted in active markets (ie a Level 1 input). Other exchange rates may
be quoted in markets that are not active (ie a Level 2 input). However,
because the foreign currency prices and/or costs generated by the mine or
oil and gas field may extend well beyond the period that quoted or
observable exchange rates are available, the exchange rate used may be
largely based on the entity-specific view on long-term exchange rates
(ie a Level 3 input).
Capital, operating and refining cost assumptions
2.58
Capital, operating and processing costs are expected to be influenced by
the characteristics of the property (eg the type, quality and location of the
mineral, oil or gas) and of the entity operating the property. Because each
property is unique, the cost assumptions are expected to be based on
Level 3 inputs but adjusted to exclude entity-specific cost drivers if
market participant estimates would use different cost drivers.
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Discount rates
2.59
The exposure draft Fair Value Measurement, at paragraph C3, proposes the
following general principles for the selection and use of discount rates in
estimating fair values, noting that these principles apply equally to
assumptions about discount rates and future cash flows:
(a)
Cash flows and discount rates should reflect assumptions that
market participants would use when pricing the asset or liability.
(b)
Cash flows and discount rates should consider only the features of
the asset or liability being measured.
(c)
To avoid double-counting or omitting the effects of risk factors,
discount rates should reflect assumptions that are consistent with
those inherent in the cash flows.
(d)
Assumptions about cash flows and discount rates should be
internally consistent. For example:
(e)
2.60
(i)
nominal cash flows should be discounted at a rate that
includes the effect of inflation and real cash flows should be
discounted at a rate that excludes the effect of inflation; and
(ii)
after-tax cash flows should be discounted using an after-tax
discount rate and pre-tax cash flows should be discounted
using a pre-tax discount rate.
Discount rates should be consistent with the underlying economic
factors of the currency in which the cash flows are denominated.
In contrast, the discount rates used in reserves estimation under the
CRIRSCO Template and the PRMS tend to be discount rates that are based
on the entity’s cost of capital (ie focusing on the risks at the entity level),
although these may be adjusted to reflect asset-specific risks such as
political, economic, fiscal, market and technical risk factors.
Project team’s view on economic assumptions
2.61
This analysis highlights that the CRIRSCO Template and the PRMS use
economic assumptions for classifying reserve and resource quantities
that may be different from the assumptions that the exposure draft
proposes should be used for preparing fair value measurement estimates
for financial reporting purposes. The CRIRSCO Template and the PRMS
use entity-specific assumptions. In contrast, financial reporting uses
market participant assumptions when they are available. However, as
discussed, many of the assumptions used in estimating quantities of
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reserves and resources would be considered Level 3 inputs in the exposure
draft. Level 3 inputs ‘shall be developed using the best information
available in the circumstances, which might include an entity’s own
data.’ The exposure draft goes on to say:
In developing unobservable inputs, an entity may begin with its own data,
which shall be adjusted if reasonably available information indicates that
(a) other market participants would use different data or (b) there is
something particular to the entity that is not available to other market
participants (eg an entity-specific synergy), and the entity is able to quantify
these adjustments. An entity need not undertake exhaustive efforts to obtain
information about market participant assumptions. However, an entity shall
not ignore information about market participant assumptions that is
reasonably available.
2.62
The project team considers that this difference in perspective between
the reserves classification systems and financial reporting will generally
not lead to materially different assumptions being selected in practice.
An entity’s internal management would normally consider the same
types of available market-based information as other market participants
before reaching their own views on future conditions. Unless observable
and directly relevant market data are available, different market
participants will have different views on the future. Therefore, in those
circumstances, and provided the entity’s own assumptions are
reasonably expected to fall within the range of market participant views,
the project team considers that, in practice, the use of entity-specific
forecast assumptions are suitable when estimating reserves and
resources for use in financial statements. However, the project team
recommends that the fair value hierarchy should be applied to determine
what assumptions are relevant to the individual facts and circumstances
of the entity and the location and type of minerals or oil and gas involved.
2.63
The selection and disclosure of economic assumptions used in classifying
reserve and resource quantities are considered further in Chapter 5.
Conditions to be satisfied before a reserve is recognised
2.64
Under the CRIRSCO Template or the PRMS, there may be instances when
a reserve cannot be recognised even though a project to develop or
expand a mine or field would generate a positive net present value using
market discount rates. Applying the definitions strictly, this could occur
when:
(a)
the cost of capital that the entity uses in making a decision on
whether to invest in a project exceeds the market discount rate; or
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(b)
2.65
the entity chooses to defer investing in a new project or expanding
an existing project, even though it will generate a positive net
present value, because it has other projects that are assigned a
higher priority to receive the investment first.
This shows that management’s intentions are incorporated into the
CRIRSCO Template and PRMS reserve definitions.
In contrast,
management’s intentions are not a feature of the Framework’s definition
of an asset. The consequence of this difference is that an entity’s reserve
quantity disclosures may not always represent the total quantity of
minerals or oil and gas that the entity may be able to recover
economically at market discount rates. The SEC, in revising its oil and gas
reserves definition, made a similar observation, which was that:
One notable difference between our final definition of “reserves” and the
PRMS definition is that our definition is based on “economic producibility”
rather than “commerciality.” One commenter believed that reserves must be
“commercial,” as stated in the PRMS definition. However, commerciality
introduces a subjective aspect to the price used to establish existing
economic conditions by factoring in the rate of return required by a
particular company before it will commit resources to the project. This rate
of return will vary among companies, reducing the comparability among
disclosures. Therefore, the adopted definition of the term “reserves” relies on
economic producibility, as proposed.*
2.66
*
The project team considers that this use of management’s intentions
should not affect the recognition of the minerals or oil and gas property as
per the project team’s view on asset recognition that is presented in
Chapter 3. Similarly, fair value measurements of minerals and oil and gas
properties would take into account the value attributable to the resources
that cannot be classified as reserves in the scenarios outlined above. For
these reasons, this difference is not considered to diminish the usefulness
of the CRIRSCO Template and PRMS definitions for asset recognition and
measurement purposes. The project team considers that the use of
management’s intentions in the CRIRSCO Template and the PRMS
definitions of reserves are appropriate for disclosure purposes.
Incorporating management’s intentions into reserves disclosures provides
useful information to users of financial reports because the disclosure
shows the estimated quantities of minerals or oil and gas that the entity
expects to develop and produce from its operations, and therefore it
provides an insight into the future cash flows that the entity might
generate from those operations. The project team’s view is that these
reserves should be disclosed separately from other quantities of minerals
SEC Final Rule Modernization of Oil and Gas Reporting (Release No 33-8995), page 41
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or oil and gas that would have a positive net present value (at market
discount rates) if they were developed and produced, but which are not
currently planned to be developed and produced by the entity. Separate
disclosure is preferred because these other quantities of minerals or oil and
gas are subject to additional uncertainties regarding if and when they will
be developed and produced. The CRIRSCO Template and the PRMS include
these quantities within their classification of mineral resources and
marginal contingent resources (for oil and gas). The disclosure of reserve
and resource quantities is considered further in Chapter 5.
Project team’s view on definitions
2.67
The project team recommends that the CRIRSCO Template and PRMS
definitions of reserves and resources are suitable for use in a future IFRS
for extractive activities. In the project team’s view, the nature and extent
of the similarities that exist between the CRIRSCO Template and the
PRMS reserve and resource definitions indicates that these definitions are
capable of providing a platform for setting comparable accounting and
disclosure requirements for both minerals and oil and gas properties.
2.68
The project team acknowledges that the report prepared by the expert
industry working group as part of the comparison study will be an
important reference for the IASB during the standard-setting phase of the
extractive activities project. Following the release of an IFRS, the
mapping report could be useful as an educational reference for users of
the financial reports of entities engaged in extractive activities.
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Chapter 3 – Asset recognition
Introduction
3.1
An important aspect of accounting for extractive activities is to identify
whether and when to recognise the assets that arise as extractive
activities are being undertaken. If no asset is recognised, then the
statement of comprehensive income will show the costs relating to
extractive activities as an expense in the period in which the costs are
incurred. On the other hand, if there is an asset that meets the
recognition criteria, under historical cost accounting, the costs incurred
are capitalised (subject to impairment) and there is no current impact on
reported income. The net impact on the statement of comprehensive
income under a current value accounting model (such as fair value)
would be similar in that the current value of the asset would be credited
to income, directionally offsetting current period expenses which would
be debited to income.
3.2
This chapter considers the initial recognition of assets relating to
extractive activities from the perspective of:
(a)
identifying the point during the extractive activity process when
there is an asset that should be recognised; and
(b)
determining the unit of account for these assets (ie what should be
accounted for as a single asset).
Asset recognition—current practice
3.3
*
It is common for entities in the minerals and oil and gas industries to
capitalise costs or recognise them as expenses according to the different
phases of extractive activities in which they occur, such as exploration
and evaluation, development and production. Accounting standardsetters have also addressed accounting for extractive activities in terms of
the phases of activity. For example, IFRS 6 Exploration for and Evaluation of
Mineral Resources focuses on two specific phases and FASB ASC section
932-360-25* separately addresses accounting for the acquisition of
properties, exploration, development and production as well as for
support equipment and facilities.
These requirements were introduced into US GAAP by SFAS 19 Financial Accounting and
Reporting by Oil and Gas Producing Companies.
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3.4
Given the widespread acceptance of the different phases of extractive
activities, the treatment of costs could be based on the nature of each
phase. Under this approach, specific activities (eg exploration) would be
prescribed as being either recognised as an asset or alternatively
recognised as an expense. Focusing on phases has the benefit of using
language that industry participants commonly use to describe their
business. This alignment between accounting and business operations
may help make the accounting policies understandable.
3.5
However, there are challenges with developing a comprehensive
accounting model based on phases. It would involve identifying the
relevant activities and costs for each phase and determining whether the
costs qualify for recognition as an asset or should be recognised as
expenses. One difficulty with this approach is that undertaking an
activity or incurring a cost does not, in itself, determine whether an
entity has something of positive economic value. For instance, the
activity may or may not have been successful or the cost incurred may or
may not result in a benefit to the entity. Consequently, an accounting
model that sets a rule, say, to capitalise costs on the basis of the specific
phase will be consistent with the definition of an asset only when the
facts and circumstances indicate that the costs incurred are generating a
benefit to the entity that meets the definition of an asset. This suggests
that it is likely to be difficult to develop reporting requirements that
result in comparable information (rather than simply being uniform
requirements)* on the basis of definitions of phases.
3.6
Another difficulty is that each phase would need to be defined in a clear and
coherent manner if different accounting treatments are to apply to
individual phases. The difficulty arises because the precise activities
undertaken in each phase can vary between the minerals and oil and gas
industries and even within the same industry. Furthermore, the phases can
overlap, sometimes with several phases being progressed at the same time.
This can make it difficult to attribute costs clearly to individual phases.†
*
The Conceptual Framework for Financial Reporting explains, at paragraph QC27, that:
‘Comparability is not uniformity. For information to be comparable, like things must look
alike and different things must look different. An overemphasis on uniformity may reduce
comparability by making unlike things look alike. Comparability of financial reporting
information is not enhanced by making unlike things look alike any more than it is by
making like things look different.’ (All references in this discussion paper to the revised
Framework are based on the most recent working draft of that document. The revised
Framework will be published shortly after the publication of this discussion paper.)
†
This has been acknowledged by PricewaterhouseCoopers in Financial Reporting in the
Mining Industry for the 21st Century (1999), paragraph 1.2, and KPMG’s Global Mining
Reporting Survey 2006, section 2.4.1.
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Asset recognition—using the Framework
3.7
For these reasons, an accounting model for extractive activities that
focuses on phases of activities is not recommended. Instead, the
approach the project team recommends is to apply the asset definition
and recognition criteria in the Framework to determine when, during the
extractive activity process, there is an asset that can be recognised in the
financial statements.
3.8
To determine at what point during the extractive activity process there is
an asset that should be recognised, it is necessary to consider that activity
in the context of the Framework’s definition of an asset and the asset
recognition criteria.
3.9
An asset is something that:
(a)
has enforceable rights that enable an entity to access or deny
(or limit) the access of others to the economic resource (in other
words, the economic resource can be controlled);
(b)
has positive economic value (in other words, future economic
benefits are expected); and
(c)
currently exists.
These are the core components of the conceptual definition of an asset.
This is apparent from both the Framework’s definition of an asset and the
proposed revised definition being considered as part of the IASB/FASB
conceptual framework project.*
3.10
3.11
*
An asset is recognised when:
(a)
it is probable that the future economic benefits will flow to the
entity; and
(b)
the asset has a cost or value that can be measured reliably.
These are the existing asset recognition criteria (as per paragraph 89 of
the Framework). However, the asset recognition criteria are under review
as part of the IASB/FASB conceptual framework project. Furthermore, in
IFRS 3 Business Combinations and as part of the redeliberations on IAS 37
Provisions, Contingent Liabilities and Contingent Assets, the IASB has decided to
include probability assessments in the measurement of an asset or
The revised definition of an ‘asset’, as tentatively adopted by the IASB and FASB, is ‘An
asset of an entity is a present economic resource to which the entity has a right or other
access that others do not have.’
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liability rather than in determining whether that asset or liability should
be recognised. Consequently, both the existing asset recognition criteria
and the implications of removing probability from asset recognition are
considered in this analysis for completeness.
Applying the Framework to extractive activities
3.12
There is a common sequence of activities undertaken by entities engaged
in extractive activities. These activities usually start with the acquisition
of legal rights to explore a defined area. Exploration and evaluation
activities produce information about the geology and the presence and
extent of any mineral or oil and gas deposit. Over time, the exploration
will increase the understanding of the deposit to the point where an
assessment can be made of whether there is a mineral or oil and gas deposit
that can be economically developed. Assuming the deposit is developed and
production begins, the development and production activities will
continue to generate information that will improve the entity’s
understanding of the deposit.
Legal rights
3.13
Various types of legal instruments convey the legal rights to permit an
entity to undertake extractive activities. These include:
(a)
property titles that provide outright ownership of the mineral or
oil and gas property associated with it.
(b)
lease or concession arrangements that are granted by the owner of
the rights (usually a government) and, in general terms, provide
the entity holding the lease or concession with the right to explore
for, develop and extract minerals or oil and gas from the property.
The terms of the lease or concession will vary in different
jurisdictions.
(c)
production sharing contracts (PSCs) with governments.*
The legal rights may be held by the entity alone or as part of a joint
arrangement to which the entity is a party. Some arrangements provide
the entity with the right to future cash flows only (and not to the minerals
or oil and gas that will be produced).
*
PSCs are common in the oil and gas industry. Although the form and content of
individual PSCs vary, the basic premise of a PSC is that it is a contract between a
national oil company of a host government and a contracting entity to carry out oil and
gas exploration and production activities in accordance with the terms of the contract,
with the two parties sharing the oil and gas produced.
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3.14
Legal rights to explore a defined area meet the definition of an asset.*
They currently exist and are enforceable rights that have a positive
economic value at the date of acquisition. They have value because they
enable the entity to explore for the unexpired duration of time that the
legal rights remain in existence and then to apply for other legal rights,
if necessary, to extract any minerals or oil and gas that are found.
The rights also have value because they preclude other entities from
commencing those activities.
3.15
The legal rights also meet the asset recognition criteria when they are
initially acquired. The probability criterion is met for the reasons
outlined in paragraph 25 of IAS 38 Intangible Assets, which states:
Normally, the price an entity pays to acquire separately an intangible asset
will reflect expectations about the probability that the expected future
economic benefits embodied in the asset will flow to the entity. In other
words, the entity expects there to be an inflow of economic benefits, even if
there is uncertainty about the timing or the amount of the inflow. Therefore,
the probability recognition criterion in paragraph 21(a) is always considered
to be satisfied for separately acquired intangible assets.
3.16
*
The criterion that an asset can be recognised only if it can be reliably
measured must be considered separately for the different measurement
bases that might be used. The legal rights asset will be capable of being
measured reliably at initial recognition if a historical cost measurement
basis applies to the asset. IAS 38 paragraph 26 notes that ‘the cost of a
separately acquired intangible asset can usually be measured reliably’.
The project team believes that the view expressed in IAS 38 is appropriate
for legal rights such as exploration rights and extraction rights. The cost
of acquiring legal rights such as exploration rights and extraction rights
can differ substantially depending on the nature of the transaction and
the jurisdiction in which those rights are acquired. For instance, in
Australia, a mineral exploration right may be acquired by the physical act
of ‘pegging’ an exploration area (ie staking a claim) and then applying for
an exploration permit through the local jurisdiction’s mining authority.
The cost of acquiring this exploration permit may be a nominal amount
that broadly corresponds to the cost to the mining authority of
processing the entity’s application for the exploration permit. Another
process for acquiring exploration rights in some jurisdictions, especially
in the oil and gas industry, is to auction new exploration blocks to the
highest bidder. In this case, the amount paid by the winning bidder
This is consistent with the IASB’s and FASB’s tentative conclusion that the right to use a
leased item meets the definition of an asset. See paragraphs 3.16 and 3.17 of the
discussion paper Leases (March 2009).
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would represent an initial assessment of the likelihood that economically
recoverable quantities of oil and gas exist on that property. In both of
these examples, there is a cost to acquire the rights and this cost is
capable of being measured reliably.
3.17
If the measurement basis at initial recognition of the asset is a current
value (such as fair value) then the legal rights asset will be capable of
being measured reliably if the acquisition of the rights is the result of an
arm’s length transaction that takes into account the likelihood that
economically recoverable quantities of minerals or oil and gas will be
found. Examples would include rights obtained in a government auction
of exploration rights or through negotiation with the current holder of
the rights. In these cases, the cost of acquiring the rights should be equal
to their current value. However, as noted in the previous paragraph with
respect to the ‘pegging’ or ‘staking’ process, it is not uncommon for
governments to grant rights on the basis of an application and payment
of a fee that does not relate to expectations about the economic value of
the property. In those circumstances, the cost of acquiring the rights
(ie the fee paid to the government) may not represent current value and
it may be more difficult to measure reliably the current value of the legal
rights. However, a decision to measure exploration properties, including
legal rights, at fair value would be dependent on the determination that
these assets could be reliably measured at fair value. The question of the
measurement basis to be used for these assets is addressed in Chapter 4.
Information
3.18
Legal rights do not exist in isolation. Associated with legal rights is
information about the property. This may include information about the
existence (or possible existence) of minerals or oil and gas, the extent and
characteristics of the deposit, and the economics of their extraction.
Often when exploration rights to a property are first acquired this
information is very limited and there are significant uncertainties.
Nevertheless the decision to acquire the legal rights for a particular
property implies some degree of information, however limited. Thus,
information about a property does not represent a separate asset but is an
integral part of the legal right asset, being the right to explore for and
extract minerals or oil and gas.
3.19
To illustrate this point, assume that Property A and Property B are
neighbouring exploration properties and that exploration rights have
been granted only for Property A. A significant oilfield is subsequently
discovered on Property A. Information that a significant discovery has
been made on Property A provides new information about the probability
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of finding oil on Property B and would be expected to increase the
purchase price of the exploration rights for that property. The entity that
subsequently acquires the exploration rights to Property B would not
recognise the information as a separate asset—the information about the
property is an integral part of the exploration rights asset and cannot be
separated from it.
3.20
Detailed exploration and evaluation activities usually begin after the
legal rights have been obtained. The information gained from these
activities generates a better understanding of whether a minerals or oil
and gas deposit exists and, if so, the characteristics of that deposit and the
prospects for economically extracting minerals or oil and gas from the
deposit. Over time, exploration and evaluation will provide more
information, thereby reducing geological and economic uncertainty.
Information that is generated during development and production will
reduce this uncertainty further. Thus, the information attribute of the
legal rights asset will continue to be modified.
3.21
New information may—or may not—add value to the legal rights asset.
For example, exploration results may either increase or reduce the
probability that there are economically producible reserves. Additional
information about the underlying reserves and resources may affect the
measurement of the asset. (Measurement is discussed in Chapter 4.) It may
also lead to the asset being derecognised (see paragraphs 3.30 and 3.31).
Additional rights and approvals
3.22
In many circumstances, even though an entity may hold all relevant
rights (eg exploration rights or extraction rights), the entity may not be
legally entitled to start exploration drilling or the extraction of minerals
or oil and gas until it has obtained various approvals. These approvals
usually need to be obtained from governments (or their agencies), and
include environmental and workplace health and safety approvals. They
are not recognised as separate assets because the future economic
benefits arising from the receipt of the approvals cannot be obtained
unless the entity also holds the relevant rights to the minerals or oil and
gas property. They can be viewed as improvements or enhancements of
the rights that are held because the receipt of the approval would remove
an explicit or implicit condition or restriction on the ability of the holder
of the rights to utilise the rights. Another view is that obtaining the
further rights and approvals reduces the legal uncertainty of eventually
extracting the mineral or oil and gas from the ground, and therefore
increases the value of the rights that are held.
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Properties in the development or production phases
3.23
As a property enters the development stage various activities are
necessary to gain access to the minerals or oil and gas deposit so that
production can begin. In general terms, these development works may be
described as a betterment of the legal rights as a result of completing
work such as:
(a)
for mineral properties: sinking shafts and underground drifts,
making permanent excavations, building roads and tunnels,
and removing overburden and waste rock in order to gain access
and be able to produce the minerals.
(b)
for oil and gas properties: gaining access to and preparing a well
location for drilling, preparing drill sites from which to drill wells,
and drilling wells to gain access and be able to produce the oil and gas.
3.24
A characteristic of such development works is that they are integral to
and inseparable from the legal rights. Development works enable cash
flows to be generated from the rights rather than generate future
economic benefits separate from the rights. This is also the case if the
legal rights are sold or otherwise transferred to another entity, as the
development works would be sold or transferred with the legal rights.
It would not be possible for the vendor to retain and use the development
works without also possessing legal rights to the minerals or oil and gas
properties. Consequently, development works are an improvement or
enhancement of the rights rather than a separate asset.
3.25
Many mines are developed in stages, with the result that production may
take place in one area while development continues elsewhere in the
mine. The project team’s view is that these development costs should be
recognised as part of the legal rights asset to the extent that they have a
future economic benefit beyond the current reporting period. Where
development costs benefit only the current reporting period, they are a
component of the cost of inventory produced in the current period and
should be accounted for in accordance with IAS 2 Inventories.
3.26
The development and production phases will also require plant and
equipment assets. Although not part of the legal rights asset, they may form
part of the same unit of account. This is discussed in paragraphs 3.60–3.64.
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3.27
The minerals or oil and gas deposit (which is often described in terms of
reserves and resources) associated with the legal rights is therefore not
regarded as a separate asset from those rights. Only when the minerals
or oil and gas are extracted does the entity have a tangible mineral or oil
and gas asset that is separate from the legal rights asset and is accounted
for in accordance with IAS 2.
3.28
This analysis shows that there is a continuum of activities from the
acquisition of the exploration rights through exploration, development
and production. Throughout this continuum the underlying asset remains
the same—the right to explore for and extract minerals or oil and gas.
Prospecting activities
3.29
Prospecting activities that are conducted before the acquisition of legal
rights generally would not be recognised as an asset because of a lack of
enforceable rights associated with the information generated from those
activities. The costs of these prospecting activities should therefore be
recognised as expenses as incurred and would not form part of the asset
that consists of the rights to explore for and extract minerals or oil and
gas. However, costs incurred during the prospecting phase should not be
recognised as expenses as incurred if they led to the creation or
acquisition of an intangible asset that can be recognised in accordance
with IAS 38 (eg a prospecting permit).
Derecognition
3.30
An asset should be derecognised when it no longer meets the criteria to
be recognised as an asset. Both IAS 16 and IAS 38 state that an asset shall
be derecognised:
(a)
on disposal; or
(b)
when no future economic benefits are expected from its use or
disposal.
Exploration is not always successful and this may lead to the realisation
that the legal rights should no longer be classified as an asset. This would
clearly be the case if the legal rights expire or are forfeited. No future
economic benefits might be expected when exploration is discontinued
because of a lack of success, no further exploration is contemplated and
there are no reasonable prospects for sale of the legal rights.
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3.31
In particular situations, future economic benefits may be unlikely but not
sufficiently certain as to require derecognition of the asset. For example,
the legal rights might extend for several years and a rise in the commodity
price that is not beyond realistic expectations would make the resource
economic to develop. In this situation, if the measurement basis is
historical cost, the asset might be subjected to an impairment test and
written down. Impairment is a measurement issue and is addressed in
Chapter 4. Alternatively, if the measurement basis is a current value, that
value would reflect the expectation of future economic benefits or the lack
thereof.
Plant and equipment
3.32
Property, plant and equipment relating to extractive activities and within
the scope of IAS 16 would be recognised in accordance with that IFRS.
The question of whether some plant and equipment assets should be
recognised separately in accordance with IAS 16, or whether they should
form part of a larger unit of account that also includes the rights
associated with mineral and oil and gas properties, is considered later in
this chapter.
Project team’s view on recognition of assets
3.33
The project team’s view is that rights and information associated with
minerals or oil and gas properties satisfy the asset recognition criteria.
3.34
Recognising information as part of the minerals or oil and gas property—
particularly during the exploration and evaluation phases—would lead to
a change in existing accounting policies for many minerals entities that
recognise all exploration costs as expenses when incurred and for those
oil and gas entities that use successful efforts accounting. For example,
under successful efforts accounting, unsuccessful drilling and seismic
surveying costs incurred during exploration and evaluation are not
recognised as assets and are therefore recognised as expenses. Viewing
the information gained from exploration as part of the minerals or oil
and gas property results in it being recognised as part of that asset. On a
historical cost basis of accounting, those costs would be capitalised as
part of the minerals or oil and gas property, unless the legal rights meet
the criteria to be derecognised. (The measurement basis of the minerals
or oil and gas property, including impairment if historical cost is the
measurement basis, is discussed in Chapter 4.)
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3.35
This treatment of costs associated with unsuccessful exploration and
evaluation activities can be contrasted with the requirements in IAS 2 and
IAS 16 for measuring the cost of inventories and self-constructed plant
and equipment. Both IFRSs state that abnormal amounts of wasted
materials, labour or other resources are not included in the cost of these
assets. The focus in IAS 2 and IAS 16 on abnormal amounts of waste
presumes a normal amount of waste that can be identified and is
capitalised—only abnormal amounts are required to be recognised as
expenses. This concept of ‘normal’ and ‘abnormal’ amounts cannot be
applied to exploration activities. Also, abnormal amounts of wasted
material, labour and other resources have no information content and
consequently bring no benefit to the inventory or self-constructed asset.
In contrast, unsuccessful exploration can improve the understanding of
the geology of the minerals or oil and gas property and therefore can
represent an enhancement to the legal right asset.
Presentation of the legal rights
3.36
The minerals or oil and gas associated with a property do not change
during exploration and development, but the uncertainties about the
quantities and other attributes of the minerals or oil and gas that exist
and can be economically extracted change significantly. Although
uncertainty remains even in the production phase, the uncertainty
during early stage exploration is much greater than during development
and production. Accordingly, some distinction in presentation and/or
disclosure might be helpful to users of financial reports to differentiate
the assets about which there is more uncertainty from the assets about
which there is less uncertainty. For example, the rights during the early
stages of the continuum might be called exploration rights and those at
a later stage might be called extraction rights. This differentiation may
provide useful information about the degree of certainty associated with
the likelihood of future production cash flows from the assets.
The project team’s view is that presenting the asset that exists across the
continuum as being of the same ‘quality’, and reporting it as such, would
not constitute faithful representation.
3.37
If rights to mineral or oil and gas properties are to be divided into two
(or more) classes, the challenge is to determine a meaningful classification
for users of financial reports. Current practice in presenting or
describing these assets varies. The KPMG 2009 survey* found that entities
use a variety of different captions in the statement of financial position
or in notes to describe their minerals assets, including development costs,
*
KPMG, The Application of IFRS: Mining (September 2009), page 31
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mining property, mining assets and property, plant and equipment.
In the oil and gas industry, FASB ASC section 932–360–25,* for example,
refers to assets such as mineral interests in properties; uncompleted wells
and related equipment and facilities; and wells and related equipment
and facilities. The project team does not think that this range of different
captions to describe similar items is helpful to users of financial reports.
3.38
*
Industry has resolved this in reporting quantities of minerals or oil and
gas as reserves and resources (in accordance with definitions such as the
CRIRSCO Template and the PRMS). There is an obvious advantage in
establishing a linkage between quantitative disclosures of reserves and
resources and the financial statements. For instance, increases in
certainty about the future cash inflows that may be generated from
minerals or oil and gas production along the continuum from
exploration to production can be reflected in the related reserves and
resources disclosure.
Consistency of quantitative and financial
information between properties that have been or will be developed
(reserves or extraction rights) and those that may (or may not) be
developed (resources or exploration rights) is critical for the purposes of
communicating useful information to users. An illustration of this
presentation is provided at Exhibit 3.1, which contains extracts from
Newmont Mining Corporation’s 2008 annual report. The second table in
Note 19 Property, Plant and Mine Development shows minerals interests
in each of the exploration, development and production phases.
An alternative presentation might show the following:
(a)
exploration properties (ie properties in the exploration or
evaluation phase, which would include properties without a
discovered minerals or oil and gas deposit and properties with a
deposit that is classified as a resource);
(b)
properties with reserves that are not in production; and
(c)
properties in production.
This section was introduced into US GAAP by SFAS 19 Financial Accounting and Reporting by
Oil and Gas Producing Companies.
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Exhibit 3.1
NOTE 19 PROPERTY, PLANT AND MINE DEVELOPMENT
At December 31, 2008
Depreciable
Life
(In Years)
Land
-
Cost Accumulated
Amortization
$
105
$
-
Net
Book
Value
$
105
Facilities and equipment
1 - 25
9,158
(4,411)
4,747
Mine development
1 - 25
2,063
(933)
1,130
Mineral interests
1 - 25
2,767
(563)
2,204
Asset retirement cost
1 - 25
384
(191)
193
-
1,753
-
1,753
Construction-in-progress
Leased assets included
above in facilities and
equipment
2 - 18
$
16,230
$
(6,098)
$
10,132
$
425
$
(268)
$
157
At December 31, 2008
Mineral Interests
Amortization
Period
(in years)
Production stage
1 - 25
Gross Accumulated
Carrying Amortization
Value
$
804
$
(556)
Net
Book
Value
$
248
Development stage
—
372
—
372
Exploration stage
—
1,591
(7)
1,584
$
2,767
$
(563)
$
2,204
Source: Edited extract from Newmont Mining Corporation 2008 annual report,
Note 19 Property, Plant and Mine Development, page 131
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Mineral Interests
Mineral interests include acquired interests in production, development and
exploration stage properties. The mineral interests are capitalized at their fair
value at the acquisition date, either as an individual asset purchase or as part of
a business combination.
The value of such assets is primarily driven by the nature and amount of
mineralized material believed to be contained in such properties. Production
stage mineral interests represent interests in operating properties that contain
proven and probable reserves. Development stage mineral interests represent
interests in properties under development that contain proven and probable
reserves. Exploration stage mineral interests represent interests in properties
that are believed to potentially contain mineralized material consisting of
(i) mineralized material such as inferred material within pits; measured,
indicated and inferred material with insufficient drill spacing to qualify as
proven and probable reserves; and inferred material in close proximity to
proven and probable reserves; (ii) around-mine exploration potential such as
inferred material not immediately adjacent to existing reserves and
mineralization, but located within the immediate mine area; (iii) other
mine-related exploration potential that is not part of measured, indicated or
inferred material and is comprised mainly of material outside of the immediate
mine area; (iv) greenfields exploration potential that is not associated with any
other production, development or exploration stage property, as described
above; or (v) any acquired right to explore or extract a potential mineral deposit.
The Company’s mineral rights generally are enforceable regardless of whether
proven and probable reserves have been established. In certain limited
situations, the nature of a mineral right changes from an exploration right to a
mining right upon the establishment of proven and probable reserves.
The Company has the ability and intent to renew mineral interests where the
existing term is not sufficient to recover all identified and valued proven and
probable reserves and/or undeveloped mineralized material.
Source: Edited extract from Newmont Mining Corporation 2008 annual report,
Note 2 Summary of Significant Accounting Policies, page 99.
Unit of account selection
3.39
The unit of account determines the level of detail/aggregation at which
assets and liabilities are recognised and presented in the financial
statements. The selection of a unit of account for a particular asset or
liability is influenced by factors such as:
(a)
adherence to generally accepted accounting principles so that the
unit of account fits within the broader accounting system; and
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(b)
meeting the information needs of users of financial reports, which
might include the provision of information that is sufficiently
granular to identify separately assets that generate independent
cash flows or are subject to particular risks.
3.40
Paragraph 82 of the Framework states that ‘Recognition is the process of
incorporating in the balance sheet or income statement an item that
meets the definition of an element …’ but it does not provide guidance
that assists with the identification and selection of particular units of
account. The current IASB/FASB conceptual framework project has
identified unit of account as an important issue, but this has not yet been
addressed.
3.41
The following principles, derived from IFRSs, may be relevant in selecting
a unit of account for minerals or oil and gas properties.
(a)
If an item’s cash flows are largely independent of the cash flows of
other items, this indicates that the item should be a separate unit
of account (see IAS 36 Impairment of Assets paragraph 68).
(b)
The unit of account should include items that are integral to, and
are not separable from, the associated rights (see IAS 17 Leases
paragraph 17 and IAS 40 Investment Property paragraph 50).
(c)
Separate units of account are required when the subsequent
accounting is different—for instance, when different items have
different useful lives (see IAS 16 paragraph 43).
(d)
Like items may be aggregated provided the aggregation is based on
significant common attributes, such as the items being subject to
common risks (see IAS 41 Agriculture paragraph 15).
(e)
Individually insignificant items may be aggregated (see IAS 16
paragraphs 9 and 46).
Unit of account considerations for extractive activities
3.42
There are two dimensions to consider in selecting a unit of account for
minerals or oil and gas properties:
(a)
the geographical boundaries of the asset—possible boundaries
include individual mine or field, individual geological area (eg a
sedimentary basin) or individual country or continent; and
(b)
the components of the unit of account that are to be recognised as
a single asset—possible components include the legal rights and
information asset (the property asset) or the property plus any
associated plant and equipment assets.
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3.43
The classification of reserves and resources (eg proved reserves, probable
reserves) to be accounted for is not considered to be a unit of account
issue. This is because the reserve and resource disclosure classifications
do not represent different ‘items’—they are different estimates of the
same item, being the recoverable minerals or oil and gas associated with
the property.
Geographical dimensions
3.44
There is a range of possible geographical boundaries that could be applied
to define the unit of account for minerals or oil and gas properties.
The possible boundaries could be set by reference to one or more of the
following attributes:
(a)
geopolitical characteristics, such as each country or group of
countries in which the entity operates (full cost accounting is an
example of this).
(b)
geological characteristics, such as:
(i)
if a wider unit of account is preferred, a basin or a geological
province; or
(ii)
if a narrower unit of account is preferred, an area of interest.
(c)
legal characteristics, eg a single area, or group of contiguous areas,
for which the relevant rights are held through property rights such
as a lease or contract.
(d)
economic characteristics, eg an area that is managed separately or
has independent cash flows.
Assessment of geopolitical and geological characteristics
3.45
Defining the geographical boundaries of the unit of account solely
according to geopolitical or geographical attributes would be
inconsistent with the principle expressed in paragraph 3.41. Aggregating
assets that share the same geopolitical risks into a single unit of account
(eg a country-based unit of account) would ignore the fact that assets in
different locations (eg different mines in a country) may be subject to very
different geological risks, may have different subsequent accounting in
terms of useful lives and impairment, and may have largely independent
cash flows. Similarly, aggregating assets that belong to a defined
geological region into a single unit of account ignores the fact that the
geological region may extend across a number of jurisdictions that are
subject to different political risks, such as government regulations and
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taxation and royalty regimes. Assets (eg mines or oil and gas fields) in a
single geological region may also have different subsequent accounting
and largely independent cash flows. Risk is important to users in
analysing an entity and therefore it is particularly important to report on,
and account for separately, assets with significantly different risks.
For these reasons, defining the individual unit of account for a minerals
or oil and gas property according to geopolitical or geological attributes
alone is not proposed.
Assessment of economic and legal characteristics
3.46
Defining the unit of account boundaries solely according to legal or
economic characteristics may not be a suitable alternative either.
In some jurisdictions, the legal rights—especially for exploration rights—
may extend across a wide area. In those cases, a unit of account defined
according to legal attributes could aggregate assets that are subject to
different geological risks or assets that have largely independent cash
flows (which may be managed as independent operations). Similarly, if
an entity has separate sets of legal rights in an area it may manage those
separate properties as a single operation. This may occur, for example,
where an entity has exploration rights that cover related areas and are
managed as a single programme or where an entity has separate legal
rights to adjacent lands and develops a single mine to extract the
minerals.
Geographical considerations for unit of account selection
3.47
Although none of the characteristics above is individually adequate for
defining the geographical dimension of the unit of account, they are all
relevant to determining the unit of account that applies to:
(a)
exploration rights (also referred to as exploration properties); and
(b)
extraction rights (also referred to as minerals or oil and gas
properties).
Geographical dimensions of a unit of account for exploration rights
3.48
Exploration programmes for a geographical area covered by a single set
of rights or by rights for adjacent areas are also usually managed as a
single exploration programme. Although rights for exploration often
cover a large geographical area, the project team thinks that it is
appropriate to treat an exploration right as a single unit of account
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during the early stages of exploration activities (see Figure 3.1). At this
time, the exploration activities may include obtaining general seismic
data and other work to gain knowledge about the area and identify
prospective areas where detailed exploration is warranted.
Figure 3.1—acquisition/initial exploration when area is considered a
single exploration area
One cost amount covers the rights to the
entire exploration area acquired
plus any subsequent exploration.
3.49
After these initial exploration activities, drilling or other more detailed
exploration will take place in the specific area or areas (within the overall
area of the exploration right) that have been identified as having the
necessary exploration potential. If two or more areas are identified for
separate exploration programmes, these areas represent separate assets
and the size of the unit of account should be redefined to be consistent
with those specific areas. Figure 3.2 illustrates this subdivision of the
exploration property into separate units of account.
Figure 3.2—exploration is subdivided into separate exploration
sub-areas
Area 1
3.50
Area 2
Area 3
Identifying separate units of account is important if historical cost is the
measurement basis for these assets. Costs incurred in Area 2 should be
depreciated against production from the minerals or oil and gas property
in that area and not against production from Area 1 or 3. On the other
hand, if exploration activities are discontinued in Area 2 or there is
another reason to test that asset for impairment, the derecognition of
Area 2 or the impairment write-down should result in the write-off of the
costs incurred in Area 2. This is because the information obtained from
exploration and evaluation activities in that area would not (materially)
improve the understanding of the geology in the other areas being
explored. This is illustrated in Figure 3.3.
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Figure 3.3—exploration in area 2 (shaded) is discontinued because of
poor results
Area 1
Area 2
Area 3
3.51
No portion of the acquisition cost of the exploration rights would be
allocated to Area 2 or written off as part of that derecognition. Those
costs are necessarily incurred regardless of the number of separate
exploration activities that are undertaken within the property. They
should be written off only if Areas 1, 2 and 3 are all derecognised.
The total amount of the acquisition cost of the exploration rights should
be included in the cost of any mine or field that is subsequently
developed.
3.52
Ultimately this process of redefining the unit of account will evolve into
the unit of account used for extraction rights (as discussed in the next
section). This is illustrated in Figure 3.4. All the costs of the unit of account
for the exploration area where a mine or oil and gas field is being developed
become the costs of the minerals or oil and gas property, even if the rights
to other parts of that area are given up or lost. If more than one mine or oil
and gas field is developed then it may be necessary to allocate certain costs,
for example the acquisition costs of the exploration rights. The allocation
principle should be similar to that in IAS 2 Inventories, which requires
allocations to be on a rational and consistent basis.
Figure 3.4—mine is developed in area 1
Area 1
3.53
Area 2
Area 3
The description above of the unit of account is intended to set an upper
limit. Entities with extractive activities could choose a smaller unit of
account, just as entities in other industries choose different units of
account according to their specific circumstances.
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Geographical dimensions of the unit of account for extraction rights
3.54
The above characteristics indicate that legal rights to minerals or oil and
gas properties that have significantly different geological, political or
other risks or generate largely independent cash flows should be
accounted for separately (ie as separate units of account). The project
team therefore proposes that the unit of account for an extraction right
should be no greater than a single area, or group of contiguous areas, for
which the rights are held, which is managed separately, and which has
largely independent cash flows. This will typically consist of a single
geological structure in a single political jurisdiction; hence the unit of
account is unlikely to include areas with very different geological or
political risks. In some cases, a mine or field that is managed as a single
operation may extend across jurisdictional borders. In those cases, the
project team thinks that the mine or field could still be treated as a single
unit of account.
3.55
The project team’s proposal would require physically separate locations
(ie ones for which the rights held are not contiguous) to be separate units
of account even if they are managed as a single unit. Because they are
physically separate they are likely to have different lives and other
economic characteristics.
Although they may be aggregated for
impairment testing in accordance with IAS 36 if their cash inflows are not
independent, they nevertheless represent separate units of account.
3.56
Similarly, there might be a single large property (ie defined according to
a single set of rights) for which two different areas are managed
separately and have independent cash flows. These represent two units
of account, as they are separate cash-generating units and accordingly
IAS 36 would require them to be treated separately in testing for
impairment. The cash-generating unit provides a ceiling for unit of
account selection because a unit of account for initial recognition and
measurement purposes should not exceed the unit of account that would
otherwise apply for subsequent measurement purposes.
3.57
The project team considers that, in practice, the geographical dimension
of a unit of account for extraction rights would usually be expected to be
a single mine or field.
Asset components
3.58
Identifying the components of a unit of account involves considering,
from a functional perspective, which assets are integral to and
inseparable from other assets within that unit of account.
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Exploration
3.59
As discussed in paragraph 3.48, the exploration right will represent the
unit of account initially.
Other assets used during exploration
(eg vehicles, drilling rigs, site offices) are not expected to be integral to
the exploration rights. Consequently, those assets would be recognised as
separate units of account from the exploration property.
Development and production
3.60
The assets that are potential candidates for collectively forming a single
unit of account are those assets that are used in upstream minerals or oil
and gas operations to produce the minerals or oil and gas. Those assets
fall into two main groupings:
(a)
legal rights to extract the minerals or oil and gas; and
(b)
plant and equipment assets.
3.61
Legal rights to extract minerals or oil and gas have been discussed in
paragraphs 3.13–3.22. They include the original acquisition of the legal
rights, additional information associated with the legal rights gained
through exploration and other means as well as development works.
3.62
Plant and equipment assets include equipment, machinery and facilities
that are used to extract, store, treat and transport the minerals or oil and
gas. An entity may have plant and equipment assets that are dedicated to
a single minerals or oil and gas property, or alternatively the plant and
equipment may be linked to several properties. For instance, an entity
may own the extraction rights for two mines on separate properties that
share a treatment plant. Therefore, the composition of assets that make
up the unit of account can also have a geographical dimension.
Possible units of account
3.63
The legal rights to extract minerals or oil and gas are the foundation of
the unit of account. In considering the extent to which plant and
equipment assets should also be included within this unit of account, the
following possible dimensions of the unit of account have been
identified:
(a)
the rights associated with a specific property including any
development works to access the deposit plus any plant and
equipment used to produce the deposit; or
(b)
the rights associated with a specific property including any
development works to access the deposit but excluding plant and
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equipment assets that are physically and commercially separable
from the property rights. Consequently, any plant and equipment
assets that are used to gain access to or to produce the minerals or
oil and gas and are separable from the property rights are treated
as separate assets.
Considerations
3.64
Factors that would influence the selection of a unit of account for the
legal rights to extract minerals or oil and gas include the following:
(a)
(b)
The carrying amount of some individual assets may have
information value, which might suggest that they should be
separately disclosed. Although many users interviewed for the
research project’s user survey indicated that they generally
consider the legal rights, development and associated plant and
equipment to be a single asset for analytical purposes, some users
saw merit in separately recognising and measuring plant and
equipment in the following circumstances:
(i)
when those assets generated separate—and material—cash
flows, such as a treatment plant that processes material from
properties owned by other entities as part of a commercial
arrangement;
(ii)
if the plant and equipment is a material asset (eg a dragline
for a coal mine) and potentially could be used elsewhere;
(iii)
when predicting the future cash flows relating to taxation
obligations, the separate recognition of plant and equipment
can provide useful information because these assets can have
implications for royalty or other obligations; and
(iv)
lenders indicated that separate recognition of separable plant
and equipment assets (eg vehicles) would be useful because it
identifies the various types of assets that could be sold
separately by the lender if the need arose. Unlike other users,
however, lenders would be able to obtain this information
directly from management if it is not available from the
financial statements.
If the measurement basis is historical cost, the impact on
depreciation if the individual items have different lives. In a
historical cost measurement environment, many assets associated
with the legal rights to extract minerals or oil and gas are
amortised over the quantity of reserves to reflect the depletion
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(ie extraction) of the mineral or oil and gas from the ground.
However, this depreciation/amortisation basis is not suitable for all
of these assets. Some items (eg mine vehicles) may have a shorter
life; while others may have a longer physical life and are able to be
redeployed for use in other locations. The components accounting
approach in IAS 16 paragraph 44 indicates that if components of an
asset have different useful lives, they should be accounted for, and
depreciated, separately.
(c)
If the measurement basis is historical cost, some assets associated
with the legal rights may become impaired or may be disposed of
separately from the other assets within the property. If this were to
happen and if the asset had not been separately identified, the unit
of account might not facilitate recognition of the impact of the
impairment or disposal event. The cash-generating unit concept in
IAS 36 also provides a constraint on the assets that can be included
in the unit of account. Although it is possible that, depending on
the facts and circumstances, the cash-generating unit may include
more than one minerals or oil and gas property (eg because a plant
and equipment asset is shared), it is also possible that there may be
more than one cash-generating unit associated with one minerals
or oil and gas property (eg if a mine and a treatment plant are
located on the same property and the treatment plant also
processes ore from other mines on commercial terms).
Project team’s view on unit of account
3.65
For exploration rights, the unit of account would initially be defined
according to the exploration rights held. As exploration and evaluation
takes place, the size of the unit of account would contract so that by the
time of development and production the geographical dimension of the
unit of account would ultimately be no greater than a single area, or group
of contiguous areas, for which the rights are held, which is managed
separately, and which would generate largely independent cash flows.
3.66
The components approach in IAS 16 may be useful in considering which
assets should be recognised separately from the legal rights to extract
minerals or oil and gas. The blanket inclusion of all plant and equipment
assets associated with a legal right to extract minerals or oil and gas is
inconsistent with the abovementioned principles and constraints.
The question is which plant and equipment assets should be included in
the same unit of account as the legal rights—and which should not.
The project team notes that the extent to which plant and equipment
assets are interrelated to the legal rights will depend on the specific facts
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and circumstances. It would therefore be difficult, and undesirable, for
an IFRS to prejudge which assets can and cannot form part of the same
unit of account as the legal rights. Professional judgement will need to
be exercised if an entity’s minerals or oil and gas properties are to be
faithfully represented in the entity’s financial statements. Nevertheless,
an IFRS for extractive activities could set some boundaries within which
professional judgement is exercised.
3.67
Paragraph 3.41 identified certain principles for determining the unit of
account for minerals or oil and gas properties. Consistently with those
principles, determining the items of plant and equipment that should be
included in the same unit of account as the legal rights to a geographical
area should be based on the following:
(a)
Plant and equipment assets that generate largely independent cash
flows represent separate units of account—in other words, the unit
of account that includes the legal rights can be no greater than a
cash-generating unit, as determined in accordance with IAS 36.
(b)
Plant and equipment assets that are physically and commercially
separable should be accounted for as separate units of account—
these are assets that could realistically be moved to other
operations and the movement of these assets could be
economically justified.
In contrast, assets are regarded as
commercially inseparable if it would be more economic to abandon
or decommission them rather than physically move them to a new
location. Examples of the latter might include assets that are
dedicated to the property because:
(c)
3.68
(i)
they are not readily movable (eg offices, concentrator,
dedicated rail facilities); or
(ii)
they are specialised so there is no other economic use for
them.
Plant and equipment assets that have different useful lives from
the legal rights (including any renewal periods that are expected to
be obtained) should be accounted for as separate units of account if
the minerals or oil and gas properties are to be measured at
historical cost.
In the project team’s view, these factors would set an upper limit to the
unit of account. Entities may decide to account for their assets using a
smaller unit of account.
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Chapter 4 – Asset measurement
Introduction
4.1
The Framework identifies several different measurement bases for assets
and liabilities but does not provide guidance on selecting between those
measurement bases. At the time this discussion paper was prepared, the
joint IASB/FASB conceptual framework project had started to address this
topic. However, the boards’ deliberations were at an early stage and did
not provide any guidance that the project team could use in addressing
measurement.
4.2
The measurement bases used in financial reporting can be broadly
categorised as either historical cost or current value. Historical cost
measures are based on the amount of cash paid or other consideration
and may vary depending on the cost elements included. (In addition,
historical cost measurements under IFRSs are subject to impairment
testing using a current value measurement.) Current value measures
include, among others, fair value and value in use.
4.3
This chapter examines the appropriate measurement basis for minerals
or oil and gas properties by considering the qualitative characteristics of
relevance and faithful representation with respect to current value and
historical cost measurement of these assets. This chapter also considers
how well each of these measurement bases meets the objective of
financial reporting, which the Framework explains is ‘to provide financial
information about the reporting entity that is useful in making decisions
about providing resources to the entity and in determining whether the
directors and management have made efficient and profitable use of the
resources provided.’ The Framework goes on to say ‘When making those
decisions, users are interested in assessing the entity’s ability to generate
net cash inflows and management’s ability to protect and enhance their
investments’.*
Existing practice
4.4
*
Historical cost is commonly used by entities in the extractive industries
to measure minerals or oil and gas properties. Extensive literature has
been developed for the oil and gas industry on two specific variations of
historical cost—successful efforts accounting and full cost accounting.
Paragraphs OB2 and OB10 respectively
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A further variant of historical cost—area of interest accounting—is
particularly prevalent in the minerals industry.
4.5
Most other non-financial assets are measured at historical cost under
IFRSs. IAS 16 Property, Plant and Equipment and IAS 38 Intangible Assets both
require assets to be measured at cost on initial recognition and permit
either the cost model or the revaluation model to be used for subsequent
measurement. In practice, the revaluation model is rarely used when
applying those IFRSs.
However, there are some other types of
non-financial assets for which fair value measurement is more common.
IAS 40 Investment Property permits investment properties to be measured
using either a cost model or a fair value model, although common
practice is to measure these assets at fair value.* IAS 41 Agriculture goes
further, by requiring biological assets related to agricultural activity to be
measured at fair value less costs to sell, unless they cannot be reliably
measured at fair value on initial recognition.
4.6
Examining existing practices may provide useful insights in developing a
new IFRS. It may be particularly useful to understand the accounting
policy choices made by preparers under existing standards. However,
existing practices may have developed for many reasons and they do not
necessarily represent accounting practices that best meet the objective of
financial reporting. For this reason, the project team’s proposals are
developed on the basis of the Framework, focusing on meeting the
objective of financial reporting.
4.7
IAS 16, IAS 38 and IAS 40 provide a choice of measurement models to
apply. The Preface to International Financial Reporting Standards explains that
the IASB does not intend to permit choice in accounting treatments,† and
so this choice is not being proposed for minerals or oil and gas properties.
Current value
4.8
The current value of an asset is based on the future cash flows that the
asset is expected to generate, either from selling the asset or from using
the asset in producing goods or providing services. Because users of
financial reports are interested in assessing the entity’s ability to
generate net cash inflows, current value measurements such as fair value
are often viewed as being conceptually consistent with the financial
*
Ernst & Young, Observations on the Implementation of IFRS, 2006, page 149
†
Preface, paragraph 13
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reporting objective of providing financial information that is useful in
making decisions about providing resources to the entity and in
determining whether the directors and management have made efficient
and profitable use of the resources provided.*
4.9
The conceptual benefits of current value measurements were confirmed
by the users consulted throughout the research project. Equity analysts
are interested in estimating the value of the entity, and the value of the
properties that contain minerals or oil and gas reserves is generally the
most substantial part of this estimate for upstream minerals or oil and
gas entities. Lenders and creditors are interested in whether the future
cash flows that are expected to be generated from these assets will be
sufficient for the entity to meet its obligations.
4.10
However, both users and preparers identified significant concerns about
whether current value estimates of minerals or oil and gas properties
would possess the qualitative characteristic of faithful representation—
and therefore whether, in practice, a current value would provide
information that could be relied on by users. Information that cannot be
relied on is not useful. These concerns focus on the methodology
required to derive a current value for minerals or oil and gas properties
and the number of assumptions required.
Approaches for estimating fair value
4.11
Fair value is one of the main forms of current value and the one that is
most commonly used in IFRSs. The following paragraphs discuss the
three generally accepted approaches for estimating fair value—the
market approach, the cost approach and the income approach.
Paragraphs 4.27–4.32 discuss other forms of current value.
Market approach
4.12
*
The market approach uses prices and other relevant information
generated in market transactions involving identical or comparable
assets. The uniqueness of each minerals or oil and gas property means
that deriving the fair value for these properties only by reference to
market transactions is rarely possible. To do so would require a recent
market transaction relating to the same property or one that has very
similar characteristics. This might occur, for example, if there had been
a recent transaction on an adjacent property. International Valuation
The Framework, paragraph OB2
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Standards Council (IVSC) Guidance Note 14 Valuation of Properties in the
Extractive Industries, at paragraph 5.3.1, makes the following comments
about the use of the market approach (which it refers to as the sales
comparison approach):
Each Mineral deposit, Petroleum accumulation and Exploration Property is
unique. Therefore, direct comparison of Mineral or Petroleum natural
resource property transactions is often difficult or inappropriate. However,
sales analysis is an important valuation tool. Sales adjustments or ratio
analysis can frequently be applied for indirect sales comparison purposes.
Sales analysis and other market analysis can often yield market factors such
as a market discount rate, a risk factor or uncertainty factor that may be used
in the Income Approach.
Cost approach
4.13
The cost approach is based on the amount that would be currently
required to replace the service capacity of an asset (often referred to as
current replacement cost). This approach is generally not suitable for
minerals or oil and gas properties because each property is unique.
Accordingly, the type of activities required and the costs incurred to find
and develop minerals or oil and gas reserves located at one property has
no correlation to:
(a)
whether a comparable minerals or oil and gas deposit exists on
another property; and if so
(b)
the activities and costs that would be necessary to find and develop
those reserves on that other property (ie the replacement cost).
A cost approach such as the Multiple of Exploration Expenditure method
is sometimes used in estimating the value of early stage exploration
properties.* However, this method would not normally be used when
sufficient geological information is available to provide a basis for
forecasting future cash flows.
*
The Multiple of Exploration Expenditure method can be applied to exploration
properties and resource properties that are considered of marginal development
potential. The project team understands that this is viewed as an emerging method for
valuing exploration or minerals or oil and gas properties.
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Income approach
4.14
The income approach calculates fair value by discounting estimated
future cash flows. Given the difficulties associated with the cost and
market approaches, fair values of minerals or oil and gas properties are
normally derived using the income approach. IVSC Guidance Note 14
notes that discounted cash flow analysis is the ‘method most commonly
used by businesses for investment decision-making within the Extractive
Industries’.*
4.15
Inputs required to calculate a fair value for minerals or oil and gas assets
using the income approach include estimates of:
(a)
the recoverable quantity of minerals or oil and gas. Such estimates
require:
(i)
interpretation of the geology of the deposit, including
estimates of total quantity (and quality) of minerals or oil and
gas contained in the deposit;
(ii)
assumptions regarding the technical factors that determine
the quantity of minerals or oil and gas that could be extracted
from the deposit, which may include:
•
for oil and gas, the reservoir pressure and flow rates;
and
•
for minerals, the mine design and metallurgical
recovery.
(b)
the production profile over the life of the property.
(c)
commodity prices, exchange rates, development and operating
costs,† taxes, royalties and other payments to governments that will
apply over the life of the property.
(d)
discount rates relating to the time value of money and risks not
reflected in the estimate of future cash flows.
*
Paragraph 5.3.3
†
The future cash outflows attributable to closure costs, such as the dismantlement and
removal of plant and equipment and the restoration of the site, will not be included in
the current value measurement. Instead, under IFRSs, a liability for closure costs will
be recognised and measured in accordance with IAS 37 Provisions, Contingent Liabilities and
Contingent Assets.
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4.16
An issue in any discussion on measuring minerals or oil and gas
properties at fair value is the level of uncertainty associated with many of
these inputs and the lack of observable market inputs.
Those
uncertainties are highest during the early stage of exploration when
there is insufficient knowledge of whether there are minerals or oil and
gas resources that can be economically produced, which makes any
estimation of recoverable quantities of the minerals or oil and gas and the
cost to produce them subjective, or indeed speculative. The uncertainty
about the minerals or oil and gas resources reduces as exploration
progresses but remains significant even in the production phase. This is
shown by the definitions of reserves and resources classifying recoverable
quantities according to different levels of confidence, such as proved,
probable and possible. Another significant uncertainty is the prices of
commodities, which are often extremely volatile, making them difficult
to predict. Futures markets may provide a market expectation for future
spot prices for some commodities but even then there is usually only a
liquid market for a relatively small number of years, which is much less
than the likely production life of many minerals or oil and gas properties.
4.17
Consequently, most inputs required for the income approach would fall
into the category of Level 3 inputs in the fair value hierarchy proposed by
the exposure draft Fair Value Measurement.* This exposure draft clearly
contemplates the use of fair value based on Level 3 inputs and proposes
guidance for deriving unobservable market inputs, for example that they
should reflect the entity’s own assumptions about the assumptions that
market participants would use in pricing the asset. A significant degree
of subjectivity will necessarily be involved in several of the inputs. As a
result, different assumptions could be selected for one or more of the
unobservable market inputs, and this could materially affect the estimate
of fair value.
4.18
Although the exposure draft contemplates the use of unobservable
market inputs, it does not imply that such inputs will always provide an
estimate of fair value that meets the criteria for use in financial
statements. The following extract from SFAS 157 Fair Value Measurements,
upon which the exposure draft is based, explains the FASB’s view:
The Board understands that for some, a measurement using a hypothetical
construct that relies on unobservable inputs raises concerns about the
resulting fair value measurement. In particular, some believe that a
hypothetical construct might not faithfully represent an actual economic
*
Chapter 2 discusses the fair value hierarchy and applies that hierarchy to economic
assumptions (eg for commodity prices) used to classify minerals or oil and gas reserves
and resources.
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phenomenon and, as such, would seem to be of questionable relevance to
users of financial reports. Some Board members share those concerns.
However, the Board agreed that concerns about fair value measurements
that are predicated on hypothetical transactions in hypothetical markets
derive from a threshold issue that relates principally to the selection of the
appropriate measurement attribute, an area of focus in the Board’s
conceptual framework project. The Board plans to continue to address the
issue of which measurement attribute should be required in individual
accounting pronouncements on a project-by-project basis.*
Thus, the fair value measurement guidance does not identify when fair
value should be used—its focus is on how to estimate fair value when an
accounting standard requires a fair value measurement.
4.19
The Framework explains that ‘To a significant extent, financial reports are
based on estimates, judgements and models rather than exact depictions
of transactions and other events and circumstances.’† An important
question is whether, in a particular case such as for minerals or oil and
gas properties, the use of unobservable market inputs will result in
faithful representation. This is not a new issue. The use of fair value or
some other form of current value as a measurement basis for minerals or
oil and gas properties is discussed in the bases for conclusions on SFAS 19
Financial Accounting and Reporting by Oil and Gas Producing Companies and on
SFAS 69 Disclosures about Oil and Gas Producing Activities. Both of those
standards conclude that the degree of uncertainty and the subjectivity
inherent in determining the inputs in order to estimate a fair value or
current value would not result in information that would be of sufficient
reliability and comparability to be used as the measurement basis in
financial statements. However, those conclusions were reached over 25
years ago and do not necessarily remain valid given the subsequent
changes in financial reporting and valuation techniques.
4.20
If fair value is used as the measurement basis for minerals or oil and gas
properties there is a need to factor in the uncertainty associated with
these Level 3 inputs. In the income method of estimating fair value, this
is usually accomplished by calculating an expected value on the basis of
different probabilities of different values for each of the various inputs.
A probability distribution of the recoverable quantity of minerals or oil
and gas would be developed, as well as probability distributions for the
relevant commodity prices and any other significant inputs with
*
Paragraph C87
†
Paragraph OB16
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significant uncertainties. Probability distributions for Level 3 inputs
would reflect assumptions made by the entity in the absence of
observable market inputs, including assumptions based on the extent of
the knowledge about the minerals or oil and gas deposit.
4.21
Using the expected value approach addresses the uncertainty inherent in
estimates of future cash flows. However, an estimate of fair value would
also include an adjustment for risk for the potential measurement error
in estimating the timing, amount or probability of future cash flows.*
4.22
The acquirer of a minerals or oil and gas property, in effect, also acquires
an option on potential improvements to future cash flow and this option
will affect the fair value. The option value would take into account the
potential upside to reserves not included in the expected value approach,
such as the potential that further exploration might discover additional
minerals or oil and gas, or a development plan not yet considered or
technology or extraction techniques not currently available might
increase the quantity of minerals or oil and gas that could be extracted
economically.
Users’ and preparers’ views on fair value measurement
4.23
Users consulted throughout the project expressed concern that some or
all of the inputs used by an entity in deriving the fair value of minerals or
an oil and gas property might be different from those that the user would
wish to apply. These users noted that the independent assessment of the
various uncertainties is a critical part of their role and that relying on
management’s assessment of these factors is inconsistent with this.
For these reasons, users indicated that they would not directly use
management’s estimate of fair value in their own analysis. Some users
noted that a fair value included in the financial statements might be
useful as a cross-check with their own value estimates. This would
require disclosure of the main assumptions such as future commodity
prices and capital costs in order to understand the reasons for the
differences between the user’s valuation and the fair value measurement
included in the financial statements.
4.24
Preparers consulted by the project team shared the users’ concerns about
the difficulty in estimating a current value and about the subjectivity
involved. They also raised concerns about the effort involved in
generating fair values, particularly for those entities with multiple
*
For more detail on risk and uncertainty in accounting measurements, see paragraphs
62–71 of Statement of Financial Accounting Concepts No. 7 Using Cash Flow Information
and Present Value in Accounting Measurements, issued by the FASB in February 2000.
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properties that might produce different commodities and be in different
jurisdictions with different political and other risks. Preparers thought
that this would impose significant preparation costs—either opportunity
costs for entities that have to redirect technical expertise from
operational activities to compliance or incremental costs to engage
outside consultants. Preparers and auditors also expressed concerns
about the additional time and cost to prepare and audit this information
and the impact on their ability to complete the financial reporting
process to meet the deadlines for regulatory reporting requirements.
Preparers told the project team that the current standardised measure of
oil and gas reserves required by FASB ASC paragraph 932-235-50-30*—
which is limited to future cash flows attributable to proved reserves—
takes four weeks or longer to prepare (depending on the specifics of the
entity’s properties). A full fair value of a minerals or oil and gas property
would take much longer. Some entities also claimed that disclosing
inputs to a fair value might require them to disclose proprietary
information (such as their future pricing outlook or their contracted
prices), which could be detrimental to their competitive position.
4.25
Fair value measurement is used in measuring impairment for minerals or
oil and gas properties and for determining the initial measurement of the
properties acquired in a business combination. This raises the question
of why fair value can be used for these purposes but not for the ongoing
measurement of those properties. Several reasons are often put forward
to explain this. An impairment or business combination will usually
affect substantially less than all of an entity’s minerals or oil and gas
properties. The calculations can often be done well in advance of the end
of the reporting period (and, in the case of a business combination,
finalised in the following period).
Impairments and business
combinations do not normally occur every reporting period. In a business
combination the value of the properties to be acquired has normally been
determined by the acquirer as part of the acquisition process. While this
may include entity-specific assumptions that do not reflect the views of
market participants, it would still be useful in determining the fair value
of the acquired properties. These factors mitigate, but do not eliminate,
the practicality and subjectivity concerns about the use of fair values in
impairment testing and business combinations.
4.26
Preparers generally concluded that fair value measurement would be
costly to implement while producing little, if any, benefit for users.
Preparers noted that users do not request fair value information and
rarely display interest in fair value or other current value information
*
This disclosure requirement was introduced into US GAAP by SFAS 69.
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about these assets that is sometimes made available in financial
statements or in regulatory filings (eg business combinations disclosures,
disclosure of a standardised measure of proved oil and gas reserves).
Accordingly, preparers do not think that measuring minerals or oil and
gas properties at fair value would meet a cost-benefit test.
Current value measurements other than fair value
4.27
Current value measurements other than fair value would also be
estimated using the income approach. In the project team’s view, a
current value measurement other than fair value can be considered a
substitute for fair value only if it provides some useful information about
future cash flows and if it addresses some of the concerns about the
preparation time and effort and subjectivity associated with estimating
the fair value of minerals or oil and gas properties.
4.28
The concerns associated with developing a fair value measurement can be
reduced by:
4.29
(a)
assigning a value to only a portion of the asset (eg proved reserves
but not probable reserves or resources); or
(b)
specifying either the values to be used for certain inputs or the
method by which those inputs are to be derived.
A current value measurement prepared on this basis would not represent
fair value. An example of such a current value measurement is the
standardised measure of discounted future net cash flows relating to
proved oil and gas reserve quantities that is required to be disclosed by
FASB ASC paragraph 932-235-50-30. The scope of this standardised
measure is limited to the future cash flows expected from the entity’s
proved reserves rather than future cash flows attributable to the entire
property—which may also include probable and possible reserves,
contingent resources and future exploration potential. Also specified,
among other things, is the use of a 10 per cent discount rate, a price
assumption equal to the average price of the commodity for the previous
year and year-end costs. The standardised measure goes some way toward
reducing the effort and limiting the need for disclosure of proprietary
data and, by reducing subjectivity, it also increases consistency of the
measurement between entities. However, there is a trade-off—the more
the inputs are specified the less likely it is that the valuation will be
relevant to a user’s understanding of the net future cash inflows
attributable to the entity’s assets.
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4.30
In practice, there is a general acceptance among users and preparers that
the standardised measure does not provide a faithful representation of
the year-end value of the entity’s oil and gas properties, or even a faithful
representation of the value attributable to its proved reserves. Many
preparers explicitly include a statement to this effect as part of their
standardised measure disclosures. One of the reasons for this is that a
historical price (such as the 31 December spot price or a twelve-month
average price)* may be significantly different from the long-range price
outlook because of short-term supply or demand factors. Nevertheless, a
standardised measure may be useful for purposes other than as a
valuation of the future cash flows expected from proved reserves. Some
users surveyed by the project team noted that they use the standardised
measure disclosure to provide a preliminary comparison of the reserve
quantities and standardised measure of different entities and to
understand changes to the entity’s standardised measure from one year
to the next. The usefulness of a standardised measure, or similar current
value measurement, as a disclosure is discussed further in Chapter 5.
4.31
In the project team’s view, the standardised measure required by FASB
ASC paragraph 932-235-50-30, or a similar current value measurement
that either assigns a value to only a portion of the asset or standardises
some of the valuation inputs, will not provide useful information about
future cash flows. Therefore, for the purposes of presenting an entity’s
statement of financial position, these forms of current value
measurement are not suitable alternatives to measuring minerals or oil
and gas properties at fair value.
4.32
Another form of current value measurement, such as a value in use
estimate, could be suitable as a substitute to fair value measurement.
The value in use measurement would, at least conceptually, provide useful
information because it would show the future cash flows that the entity
expected to generate from its assets. However, the current value
measurement would not address the concerns of users (see paragraph 4.23).
It would also not use market-based inputs (where available) and therefore
might be less useful to users than fair value. Furthermore, a value in use
measurement would not address any of the concerns raised by preparers
about the preparation cost and effort required and the concern that
commercially sensitive information might be disclosed. For these reasons,
the project team’s view is that fair value is the most suitable current value
measurement basis that could be applied to minerals or oil and gas
properties.
*
Accounting Standards Update 2010-03—Extractive Activities—Oil and Gas (Topic 932): Oil and
Gas Reserve Estimation and Disclosures now require the standardised measure to be
prepared using a 12–month average commodity price rather than a year-end price.
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Fair value measurement at initial recognition
4.33
The initial recognition of minerals or oil and gas properties is made either
when the exploration rights have been acquired or when the property is
subsequently acquired by the entity through either an asset acquisition
or a business combination.
Paragraphs 4.24–4.26 identify issues
associated with preparing current value estimates for these assets.
A broader issue that may arise concerning the use of fair value at initial
recognition is the potential for day 1 gains or losses to be recognised
when exploration rights are acquired by staking a claim on an
exploration area. As noted in Chapter 3, the purchase price of these rights
is unlikely to correspond to the asset’s fair value. Therefore, in these
cases, it would need to be determined whether it is appropriate to
recognise a gain or loss on initial recognition of these exploration rights.
4.34
An additional issue arises if the current value measurement basis is not
fair value. As the consideration given to acquire a minerals or oil and gas
property will, in many cases, be equivalent to the asset’s fair value, it
would need to be determined whether the initial measurement of the
asset should be at current value (as defined by the future IFRS) or fair
value (as would be required by, for example, IFRS 3 Business Combinations).
If the measurement basis is a current value other than fair value, there is
likely to be a gain or loss when the property is first measured at that
current value.
Fair value measurement after initial recognition
4.35
The main issues associated with the current value measurement of
minerals or oil and gas properties after initial recognition are the
frequency of the remeasurement (which is discussed in the following
paragraphs) and the implications of the remeasurement on the statement
of comprehensive income (which is discussed later in this chapter).
4.36
In remeasuring other types of non-financial assets at fair value, IFRSs
require the remeasurement to be performed either:
(a)
each reporting period, including interim periods—which is the
approach adopted by IAS 40 and IAS 41; or
(b)
on a periodic basis, but with sufficient regularity to ensure that, at
the end of the reporting period, the asset’s carrying amount does
not differ materially from its fair value—which is the approach
adopted by IAS 16 and IAS 38.
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4.37
In the project team’s view, this distinction between the frequencies of
these remeasurements is unlikely to be relevant in practice for minerals
or oil and gas properties. This is because the fair value of these assets is
continually changing as more information is obtained about the
property, as economic conditions change, and as the minerals or oil and
gas are extracted. Therefore, if the property is not remeasured at fair
value at the end of each reporting period, it is likely that its carrying
amount would materially differ from its fair value. Unless fair values
were determined at each reporting date, the measurement of those assets
would not faithfully represent the entity’s financial position or the
entity’s financial performance for the reporting period. For this reason,
the project team thinks that if minerals or oil and gas properties are to be
measured at fair value, those assets would have to be remeasured at
fair value each reporting period, including interim periods. As noted
in paragraph 4.24, this would have substantial preparation cost
implications for minerals and oil and gas entities.
Historical cost
4.38
The historical cost of a minerals or oil and gas property includes the cost
of acquiring the exploration and extraction rights. It also includes the
cost of any activities undertaken after the acquisition that enhance the
value of the exploration and extraction rights (such as exploration and
evaluation activities that generate information about the minerals or oil
and gas deposit and development activities that allow access to the
deposit).
4.39
Historical cost is generally regarded as providing a verifiable measure of
the cost of acquiring and developing a property. Often these costs can be
observed from a transaction, which suggests that historical cost is an
objective measurement. This is not always true as an asset’s historical
cost at initial recognition can be influenced by judgements made in, for
example, cost allocation decisions relating to the unit of account
(as discussed in Chapter 3) and determining the initial carrying amount
of individual assets acquired in either a business combination or in a
multiple asset acquisition. Provided these judgements are exercised in a
manner that makes the historical cost complete, neutral and free from
material error, the historical cost would be a faithful representation of
the cost to acquire, explore and develop a property.
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4.40
A historical cost measurement that is a faithful representation of the cost
of acquiring, exploring and developing a property might be useful for
assessing management’s stewardship of the economic resources
entrusted to it by investors and creditors. The assessment might involve
calculating performance measures such as the return on capital, which
indicates how well management has invested the funds under its control
(ie in general terms, by measuring the income earned from the capital
invested). Most existing historical cost measurement models are
somewhat deficient when used for this purpose because they are not
representative of the total capital invested. Some costs may have been
recognised as expenses as incurred and other costs may have been written
off subsequently either through systematic depreciation charges or
impairment write-downs of unrecoverable capitalised costs. Some
analysts may make adjustments for this when calculating these
measures. The relevance of historical cost for measuring performance is
also limited because the return is calculated by comparing revenues in
current prices with costs measured in historical prices. Although this
comparison provides an accurate measure of the income earned over
time, it does not provide an accurate measure of management’s return
relative to the current value of its assets.
4.41
The historical cost of a minerals or oil and gas property generally provides
relevant information that is useful in assessing future cash flows only
when the asset’s historical cost equals its fair value. This normally occurs
when the rights to the property have been acquired in an exchange
transaction between a willing buyer and a willing seller. Such situations
include rights to the property acquired through an auction process or by
negotiation (including a farm-in* or business combination). In these
situations, the historical cost—being the purchase price—would take into
account information about the property and expectations about future
economic conditions that existed at the time of the acquisition. However,
there are other situations in which the historical cost of acquiring rights
does not reflect the fair value of the rights. An example is rights obtained
by staking a claim to an area and then paying a fee to the government to
acquire the exploration rights. This fee would not normally take into
account the exploration potential of the property, and in these situations
the historical cost at initial recognition would not provide information
relevant for assessing future cash flows.
*
A farm-in or farm-out arrangement is defined in the IASC Issues Paper Extractive Industries
as ‘an agreement by which the owner of operating rights in a mineral property (the
farmor) transfers a part of that interest to a second party (the farmee) in return for the
latter’s paying all of the costs, or only specified costs, to explore the property and perhaps
to carry out part or all of the development of the property if reserves are found’.
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4.42
The relevance of a property’s historical cost for assessing future cash
flows diminishes over time as subsequent exploration and evaluation
activities generate more information about the property, including
geological information and estimates of the size, quality and economic
recoverability of any minerals or oil and gas discovered at the property.
While a great degree of expertise and effort enters into exploration
decisions, there is still significant uncertainty over the outcome of
exploration. Different decisions affect the amount of exploration work
required and costs incurred before a minerals or oil and gas reserve is
discovered. As a result, the historical cost of exploration is not relevant
for assessing future cash flows because there is no correlation with the
future cash flows that may be generated from the production of minerals
or oil and gas from the property.
4.43
The relevance of a property’s historical cost for making economic
decisions also diminishes as expectations about future economic
conditions change. For example, the ability of the entity to generate cash
inflows from a property depends on commodity prices that may change
significantly over time. Prices affect not only the amount received for a
given quantity of mineral or oil and gas sold, but also the quantity of the
reserves that can be economically produced. A property may therefore
have a very positive cash flow outlook one year and, if commodity prices
fall, may change to a marginal cash flow outlook—or worse.
Historical cost measurement after initial recognition
4.44
The historical cost of an asset after initial recognition equals the sum of
costs incurred that are attributable to the asset less accumulated
depreciation (or amortisation) and impairment write-downs.
The following paragraphs consider the application of depreciation and
impairment requirements to the historical cost measurement of an
exploration property (ie an asset in the exploration or evaluation phase)
or a minerals or oil and gas property (ie an asset in the development or
production phase).
Depreciation
4.45
Depreciation expense should be recognised for exploration properties
and minerals or oil and gas properties to acknowledge that, over time, the
future economic benefits embodied in those assets are being consumed.
Depreciation calculations allow for a systematic recognition of the
decline in value of these assets as represented by their historical cost
carrying amounts. Conceptually speaking, an alternative to calculating
depreciation would be to require the asset to be tested for impairment
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each reporting period. This alternative to recognising depreciation is
likely to require frequent recoverable amount assessments under IAS 36
Impairment of Assets, especially once minerals or oil and gas are being
extracted. Testing exploration properties and minerals or oil and gas
properties for impairment is discussed in paragraphs 4.50–4.76 below.
4.46
The basis for calculating depreciation (or amortisation) for exploration
properties and minerals or oil and gas properties is set out in IAS 16 or
IAS 38, depending on whether either the asset or its components are
tangible or intangible in nature. As discussed in Chapter 3, some of the
components of an exploration property or a minerals or oil and gas
property may have different useful lives and so would need to be
depreciated separately.
4.47
Current practice in calculating depreciation for these assets under
existing IFRSs can be broadly summarised as follows:
4.48
(a)
for the exploration rights component of an exploration property—
depreciation usually starts when the exploration rights are
acquired (because this is typically when the rights are available for
use) and the calculation of depreciation expense is based on the
term of the right;* and
(b)
for minerals or oil and gas properties—depreciation starts when the
property is ready for production and depreciation expense is
usually calculated on a units of production basis to reflect the
pattern in which the asset’s future economic benefits are expected
to be consumed—ie by the depletion of mineral or oil and gas
reserves through production.
The project team does not propose that the basis for calculating
depreciation for these assets should be significantly different from
existing IFRSs. However, the project team thinks that, if historical cost is
adopted as the measurement basis for these assets, there are some
practical application issues that should be considered when drafting a
future IFRS for extractive activities. These issues are related to the
calculation of depreciation on a units of production basis for minerals or
oil and gas properties, including:
(a)
*
whether the units of production formula should be based on
revenues (such as gross revenues) or physical units (which,
particularly in the minerals industry, could be either the ore
produced or the mineral contained in the ore produced);
Depending on the entity’s accounting policy under IFRS 6, this depreciation expense
may form part of the costs of its exploration and evaluation asset.
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(b)
whether the units of production formula should be calculated on
proved reserves only or on the sum of proved and probable reserves
(which is the best estimate of minerals or oil and gas that will be
extracted), or potentially also include some resources
classifications if it is expected that future development will take
place at the mine or field and, as a consequence, will prolong the
overall life of the mine or field; and
(c)
how to apply units of production depreciation when more than one
commodity is extracted from the same property.
These application issues are discussed in Chapter 7 of the Issues Paper
Extractive Industries, which was published by the IASC Steering Committee
on Extractive Industries in November 2000.
4.49
To address these application issues, the project team proposes that a
uniform basis for calculating depreciation expense should apply to both
minerals properties and oil and gas properties. This is consistent with the
research project’s guiding principle that comparable accounting and
disclosure requirements should be considered for the minerals and oil
and gas industries.
Impairment
4.50
IAS 36 applies after initial recognition and measurement to ensure that
an entity’s assets are carried at no more than their recoverable amounts.
IAS 36 requires an entity to assess at each reporting date whether there is
any indication that its assets may be impaired. If any such indication
exists, the entity must estimate the recoverable amount of the asset
(or the cash-generating unit to which the asset belongs). IAS 36 therefore
sets an upper limit on the carrying amounts of assets.
4.51
IAS 36 defines an impairment loss as ‘the amount by which the carrying
amount of an asset or a cash-generating unit exceeds its recoverable
amount’. Impairment is therefore a measurement issue. Chapter 3
discusses derecognition of a minerals or oil and gas property because it
no longer meets the definition of an asset or the recognition criteria—for
example, when the legal rights to a property expire or no further work
will be carried out on the property.
4.52
The specific indications identified in IAS 36, while not exhaustive,
suggest that an asset does not need to undergo a recoverable amount
assessment unless there has been an adverse change or if new
unfavourable information becomes available after the asset was initially
recognised or remeasured (ie written down as a result of a prior
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impairment). The indications of impairment approach therefore acts as
a filter to identify the assets that need to undergo a recoverable amount
assessment. This avoids imposing on entities the cost and effort of
comparing the carrying amount of each asset to its recoverable amount
every period.
4.53
As noted in Chapter 1, the research project has not been constrained by
existing IFRSs in considering how to account for exploration properties
and minerals or oil and gas properties. With that in mind, the remainder
of this section on impairment considers whether IAS 36 should apply to
exploration properties and minerals or oil and gas properties.
The analysis is presented separately for each asset because of their
different characteristics, relating principally to the availability of
information about the existence and quantities of minerals or oil and gas
that can be extracted economically.
Applying IAS 36 to minerals or oil and gas properties
4.54
IAS 36 currently applies in testing minerals or oil and gas properties for
impairment. With these assets, an entity is expected to have access to
sufficient information about the minerals or oil and gas property to test
whether the carrying amount of the asset is impaired. Typically, a
detailed project cash flow model is prepared when an entity is deciding
whether to develop a mine or field on the property. At that time,
sufficient information is available to assess whether the carrying amount
of the property is impaired and, if necessary, any impairment loss would
be recognised at that time. This is consistent with the requirement in
paragraph 17 of IFRS 6 Exploration for and Evaluation of Mineral Resources that
‘exploration and evaluation assets’ are to be assessed for impairment at
the time when the technical feasibility and commercial viability of
extracting the mineral resource are demonstrable.
4.55
During the development and production phases, the need to test for
impairment will often be the consequence of changes in the major
assumptions that were used when making the development decision.
The types of changes in assumptions that may have an effect on the
entity’s ability to recover the carrying amount of the asset include
decreases in commodity prices or increases in development or production
costs, decreases in reserves estimates, delays in the development or
production schedule, or legal or regulatory changes (eg changes in tax or
royalty rates). Because those changes in assumptions will be considered
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when the entity revises its cash flow models and reserves and resources
estimates for the property, the entity should have access to sufficient
information to test for impairment in accordance with IAS 36.
4.56
Most of the practical issues that have arisen in applying IAS 36 to minerals
or oil and gas properties are not unique to extractive activities and relate
to specific requirements within IAS 36, such as:
(a)
identifying the cash-generating unit for minerals or oil and gas
properties when there is an active market for intermediate
products or when infrastructure is shared with other mines or
fields owned by the entity or third parties; and
(b)
the exclusion of future capital expenditures in calculating the
asset’s value in use.
Accordingly, the project team does not think that these issues justify
applying an alternative impairment model to that in IAS 36 for minerals
or oil and gas properties.
Applying IAS 36 to exploration properties
4.57
In most instances, exploration properties would be subject to an
impairment test each reporting period if IAS 36 applied to these assets
instead of IFRS 6. Even if none of the indications of impairment identified
in IAS 36 are present, the fact that exploration activities have been
undertaken during the reporting period would generally mean that an
impairment test is necessary to determine whether the property’s carrying
amount is less than its recoverable amount. This is because, as noted in
paragraph 4.42, there is no relationship between the cost of exploration
activities and what is gained from that exploration. An exploration
programme may find minerals or oil and gas worth many times the cost of
the exploration—or it may find nothing. Typically, exploration results will
lie somewhere between these extremes. But until sufficient information is
available to evaluate the exploration results and reach a conclusion on
whether economically recoverable quantities of minerals or oil and gas
have been found, it is not possible to make any (reliable) judgements that
the carrying amount of an exploration property (ie the cost of the
exploration rights and any subsequent exploration and evaluation
activities) would be less than its recoverable amount.
4.58
An impairment test under IAS 36 requires a current value (the higher of
fair value less costs to sell and value in use) to be estimated. As noted
earlier in this chapter, there are practical challenges in using current
value to measure exploration properties and minerals or oil and gas
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properties.* If historical cost is the basis of measurement and exploration
properties are required to be measured at current value each period in
order to determine if the assets are impaired, then the historical cost
basis for these assets is really a current value basis—albeit one-sided in
that it would generally result only in a write-down of the value of the
asset; there would be no upward revaluation (unless the impairment is
subsequently reversed).
4.59
On the basis of this analysis, the project team is proposing that the IAS 36
impairment model should not apply to exploration properties for the
following two reasons:
(a)
Estimating the recoverable amount for most (or all) exploration
properties each reporting period is likely to involve as much effort
as adopting a current value measurement basis. Consequently, if
performing a recoverable amount assessment each reporting
period were feasible, there would be less reason to choose historical
cost as the measurement basis for these assets. This is because, at
least in conceptual terms, measuring these assets at current value
provides more relevant information than if they are measured at
historical cost.
(b)
It would be difficult—if not impossible—to limit the number of
properties for which an impairment test is required each reporting
period through the use of indications of impairment based on
adverse changes or new information. This is because there will
normally be new information available each reporting period as a
result of exploration and evaluation activities completed in the
period that will be relevant for making judgements about the
recoverability of an exploration property’s carrying amount.
Furthermore, the cost of those activities increases the carrying
amount that is to be tested for impairment.
Alternatives to applying IAS 36 to exploration properties
4.60
Alternatives to applying the IAS 36 impairment model to exploration
properties include:
(a)
*
Option A—revisiting the project team’s view on initial recognition
in Chapter 3 to require instead that exploration and evaluation
Although professional valuers can be engaged to value (or provide a range of values for)
an individual property, the application of IAS 36 to extractive assets would require every
entity’s properties to be valued every reporting period in sufficient time to meet
financial reporting requirements. This is not expected to be possible without incurring
significant preparation costs.
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costs are recognised as expenses as incurred until sufficient
information is obtained to indicate the existence of economically
recoverable reserves;
(b)
Option B—allowing entities to recognise an impairment loss for an
exploration property without having to calculate recoverable
amount in cases where preparing that calculation would involve
undue cost or effort; or
(c)
Option C—identifying indications of impairment that are different
from those in IAS 36 and apply specifically to exploration
properties.
Option A—Revisiting the project team’s view on initial recognition
4.61
The project team’s view on initial recognition, as outlined in Chapter 3,
is that the information obtained from both successful and unsuccessful
exploration and evaluation activities improves the understanding of the
geology of the exploration property. Consequently, the costs of these
activities should be capitalised because they are an enhancement to the
asset even though sufficient information may not yet be available to
indicate the existence of economically recoverable quantities of minerals
or oil and gas.* An alternative to the project team’s view on initial
recognition would be to recognise the asset only when sufficient
information is available to indicate the existence of economically
recoverable quantities of minerals or oil and gas. This alternative would
result in most exploration and evaluation costs being recognised as
expenses as incurred unless those costs are otherwise capable of being
recognised as assets in accordance with IAS 16 or IAS 38.
4.62
This option would be somewhat similar to successful efforts accounting
in the oil and gas industry but it would require some costs that are
generally capitalised under existing practice to be recognised as
expenses. For example, the cost of drilling a successful oil exploration
well may need to be recognised as an expense as incurred if the cost is
incurred before sufficient information is available to assess whether the
reservoir that has been discovered contains economically recoverable
quantities of oil or gas. Exploration properties would be recognised in the
financial statements—but would be measured at the cost of acquiring the
rights. This option also requires an entity to determine when there is
sufficient knowledge about the property for an estimate of future cash
flows to be made.
*
The authors of the discussion paper Initial Accounting for Internally Generated Intangible
Assets, published by the Office of the Australian Accounting Standards Board in 2008,
reached a similar view—see, in particular, paragraphs 47, 48 and 75–87.
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4.63
In the project team’s view, this option is inconsistent with the application
of the asset definition and recognition criteria (as discussed in Chapter 3),
because it would lead to the recognition as expenses of costs that improve
knowledge about an exploration property and therefore misstate the
financial performance of an entity as reflected in the statement of
comprehensive income. (This is discussed further at paragraph 4.84 below.)
Option B—Undue cost or effort exemption
4.64
Under this option, IAS 36 would apply to exploration properties, but
entities would be provided with an ‘undue cost or effort’ exemption from
calculating recoverable amount for an exploration property if the
benefits of calculating recoverable amount did not justify the costs
involved. Entities taking this option would write down the property’s
carrying amount to zero. The exemption would be taken property by
property because there may be some properties for which a comparison
can be made between its recoverable amount and its carrying amount
with reasonable effort. In subsequent reporting periods, if there were
sufficient information to indicate the existence of economically
recoverable quantities of minerals or oil and gas, IAS 36 would require a
reversal of the impairment.
4.65
This option has the advantage of ensuring that the entity’s statement of
financial position is not overstated during the early stages of exploration
and that the cost of the minerals or oil and gas property is not
understated when the property is likely to proceed to development,
because by then the impairment would be expected to have reversed.
A disadvantage of providing an ‘undue cost or effort’ exemption is that it
could be used to facilitate the ‘smoothing’ of an entity’s financial
performance between reporting periods. Furthermore, the use of ‘undue
cost or effort’ exemptions has previously been proposed—but not
subsequently adopted—in amendments to IFRS 3 Business Combinations
(about measuring non-controlling interests at fair value), IAS 1 Presentation
of Financial Statements (about reclassification of comparative amounts and
disclosure of key assumptions and other sources of estimation
uncertainty) and IAS 8 Accounting Policies, Changes in Accounting Estimates and
Errors (about retrospective application of voluntary changes in accounting
policies and retrospective restatement for fundamental errors). In each
of those cases, the IASB decided not to use an ‘undue cost or effort’
exemption because an exemption based on management’s assessment of
undue cost or effort was too subjective to be applied consistently by
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different entities.* The project team agrees that the same concern would
arise with the approach adopted for testing exploration properties for
impairment.
Option C—Identifying other indications of impairment
4.66
This option involves identifying indications of impairment that apply
specifically to exploration properties since, as noted in paragraphs 4.57–4.59,
the indications in IAS 36 cannot be applied effectively to determine
whether an exploration property should be tested for impairment.
An indication of impairment would have to be able to predict whether
the carrying amount of a specific exploration property is likely to be
greater than its recoverable amount without requiring the asset’s
recoverable amount to be calculated.
4.67
The types of impairment indicators identified in existing standards as
being appropriate for exploration properties mainly address whether there
is an asset that can continue to be recognised rather than whether the
carrying amount of that asset is recoverable. IFRS 6 paragraph 18 requires
exploration and evaluation assets to be tested for impairment ‘when facts
and circumstances suggest that the carrying amount exceeds the
recoverable amount’. The facts and circumstances listed in paragraph 20
of IFRS 6 are:
*
(a)
the period for which the entity has the right to explore in the
specific area has expired during the period or will expire in the
near future, and is not expected to be renewed.
(b)
substantive expenditure on further exploration for and evaluation
of mineral resources in the specific area is neither budgeted for nor
planned.
(c)
exploration for and evaluation of mineral resources in the specific
area have not led to the discovery of commercially viable quantities
IFRS 3, paragraph BC215; IAS 1 paragraph BC36 and IAS 8 paragraph BC24. The Bases for
Conclusions on IAS 1 and IAS 8, in those paragraphs, also note that balancing costs and
benefits is a task for the IASB when it sets accounting requirements rather than for
entities when they apply those requirements. ‘Undue cost or effort’ exemptions were
also proposed during the development of IFRS 1 First-time Adoption of International
Financial Reporting Standards. However, the project team regards IFRS 1 as a special case
that does not provide a general precedent for the development of exemptions in other
IFRSs. IFRS 8 Operating Segments provides an exemption from some of the disclosures if
the necessary information is not available and the cost to develop it would be excessive.
This is also a special case: paragraph BC47 of IFRS 8 suggests that this wording was used
to ensure convergence with SFAS 131 Disclosure about Segments of an Enterprise and Related
Information.
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of mineral resources and the entity has decided to discontinue
such activities in the specific area.
(d)
sufficient data exist to indicate that, although a development in
the specific area is likely to proceed, the carrying amount of the
exploration and evaluation asset is unlikely to be recovered in full
from successful development or by sale.
The first three of these four criteria address derecognition of the asset,
which was discussed in Chapter 3. The fourth criterion addresses
recoverability but, as previously discussed, sufficient data will not
normally exist to determine that ‘the carrying amount of the exploration
and evaluation asset is unlikely to be recovered in full’.
4.68
In US GAAP for oil and gas extractive activities, an entity can continue to
capitalise drilling costs if an exploratory well has found a sufficient
quantity of oil and gas to justify its completion as a producing well and
the entity is making sufficient progress assessing the reserves and the
economic and operating viability of the project. FASB ASC paragraph
932-360-35-19 states that when determining whether an entity is making
sufficient progress on those assessments all relevant facts and
circumstances should be evaluated. The paragraph includes the
following non-exhaustive list of indicators that an entity is making
sufficient progress:
a.
commitment of project personnel who are at the appropriate levels
and have the appropriate skills
b.
costs that are being incurred to assess the reserves and their potential
development
c.
an assessment process covering the economic, legal, political, and
environmental aspects of the potential development is in progress
d.
existence (or active negotiations) of sales contracts with customers for
the oil and gas
e.
existence (or active negotiations) of agreements with governments,
lenders and venture partners
f.
outstanding requests for proposals for development of any required
facilities
g.
existence of firm plans, established timetables, or contractual
commitments, which may include seismic testing and drilling of
additional exploratory wells
h.
progress that is being made on contractual arrangements that will
permit future development
i.
identification of existing transportation and other infrastructure that
is or will be available for the project (subject to negotiations for use).
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However, these criteria all address whether there is sufficient support to
continue recognising an asset. They do not address the recoverability of
the asset’s carrying amount.
4.69
The project team has not been able to identify any indications of
impairment that would be useful in predicting whether and when the
carrying amount of an exploration property is not recoverable. This is
because if information about the presence of minerals or oil and gas on
an exploration property is too limited to use for predicting future cash
flows (or otherwise determining the recoverable amount), the
information is likely to be equally insufficient for any objective indicators
to make accurate predictions about the recoverability of a property.
To make such predictions, the indicators would have to distinguish
between situations where:
(a)
the information, while limited, is sufficiently positive and the
carrying amount of the property sufficiently low for the likelihood
of the carrying amount being recoverable to be very high;
(b)
even though exploration will continue, the exploration results to
date make it very unlikely that the carrying amount will be
recovered in full; and
(c)
most commonly, there is insufficient information to judge
recoverability with any reasonable degree of confidence.
4.70
For this reason, testing exploration properties for impairment may need
to be based largely on management’s expectations of the recoverability of
its properties rather than on the existence of any objective indicators that
those properties are impaired. Because different managements may
manage their exploration and evaluation activities differently and have
different perceptions of how well those activities are progressing, the
project team thinks that it would also be difficult to prescribe how
management should assess the recoverability of its properties.
Consequently, this option identifies the following principle for testing
these assets for impairment—management should be required to write
down an exploration property only when, in its judgement, there is a
high likelihood that the carrying amount of the property would not be
recovered in full.
4.71
Compared with IAS 36, this principle is intended to defer when
exploration properties are tested for impairment. This is because, until an
exploration programme is sufficiently advanced, it is unlikely that
management would have enough information to assess whether it is
highly likely that the carrying amount of the property is not recoverable.
The project team thinks that how an exploration programme is managed
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should provide insight as to whether management has sufficient
information to make such an assessment.
For instance, more
information would need to be obtained and analysed before an
assessment can be made about the recoverability of a property if
exploration has only recently begun on the property or if exploration
results to date support continuing with the exploration programme.
In contrast, if management is considering significant reductions to its
exploration programme, such as planning to abandon the property or
wind down its exploration and evaluation activities on that property
(eg by reallocating equipment and personnel to other exploration
programmes), then this may indicate the need for an impairment test.
4.72
In addition, given the absence of objective indicators to predict whether
exploration properties are impaired, this option would include a separate
set of indicators to assess whether an asset can continue to be recognised.
This is consistent with the approach adopted in IFRS 6 and US GAAP.
These indicators would be based on the existence of evidence that the
asset can continue to be recognised (ie positive indicators) rather than on
the absence of evidence that would indicate that the asset is impaired or
should be derecognised (ie negative indicators). Consequently, the
indications may be based on facts and circumstances where:
(a)
minerals or oil and gas has been discovered on the property, but
further exploration and evaluation is required to assess the size
and quality of the deposit and to determine whether the minerals
or oil and gas can be extracted economically; and
(b)
minerals or oil and gas have not yet been discovered, but
substantive exploration and evaluation activities in a specific
location within the exploration property are continuing. This
indication links to the project team’s view on the unit of account of
an exploration property (see Chapter 3), because an exploration
property (or part thereof if there is more than one unit of account
for that property) will be derecognised when exploration and
evaluation activities cease or are abandoned on the property (or
that part of the property).
Project team’s view on impairment of exploration assets
4.73
The project team recommends that an exploration property should be
written down to its recoverable amount in those cases where
management has enough information to make this determination.
However, for most exploration properties, this information is not likely
to be available while exploration and evaluation activities are
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continuing, and particularly when those activities are not yet at an
advanced stage. Accordingly, the project team also recommends that
exploration properties should be tested for impairment on a basis that is
consistent with Option C. Therefore, management would be required:
4.74
(a)
to write down an exploration property only when, in its
judgement, there is a high likelihood that the carrying amount
will not be recoverable in full; and
(b)
to apply a separate set of indicators to assess whether its
exploration properties can continue to be recognised as assets.
Different managements may take different views on whether an
exploration property should be written down—and by how much. This is
unavoidable given the very limited information that exists for the typical
exploration property. For this reason, the project team thinks that an
entity’s financial report should also include:
(a)
separate presentation of exploration properties in the financial
statements (as per the project team’s view in Chapter 3);
(b)
for exploration properties written down in the period, disclosure of
the factors that led management to determine that the exploration
properties were impaired and the remaining carrying amount of
exploration properties that have been impaired; and
(c)
for exploration properties not written down in the period,
disclosure of management’s views on why those properties
continue to be capitalised in the financial statements.
4.75
Paragraph BCZ24 of the Basis for Conclusions on IAS 36 states that the
‘IASC acknowledged that an enterprise would use judgement in
determining whether an impairment loss needed to be recognised.
For this reason, IAS 36 included some safeguards to limit the risk that an
enterprise may make an over-optimistic (pessimistic) estimate of
recoverable amount’. The project team thinks that the disclosures about
exploration properties, as outlined in paragraph 4.74, should provide an
appropriate safeguard against an entity making any unduly optimistic or
pessimistic estimates of a property’s recoverable amount.
4.76
The project team thinks that an impairment assessment should be
carried out separately for each exploration property (with the unit of
account determined in accordance with the project team’s
recommendations in Chapter 3). Consistently with IAS 36, the carrying
amount of an exploration property that is impaired should be written
down to its recoverable amount. In some cases, this recoverable amount
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assessment could be performed at a cash-generating unit level rather
than at an individual property level. However, the project team is not
proposing to continue the accounting policy choice permitted by IFRS 6
to allocate exploration properties to groups of cash-generating units for
the purpose of assessing impairment.
A mixed measurement basis
4.77
Rather than treat historical cost and fair value as mutually exclusive
measurement alternatives for these assets, another approach is to
consider measuring the assets at historical cost until their fair values can
be estimated with greater reliability. This approach would overcome
some of the concerns identified earlier in this chapter about estimating
the asset’s fair value when there is limited information about the
existence or quantity of economically recoverable minerals or oil and gas
on the property. However, switching the measurement basis from
historical cost to fair value at a predefined stage during the life of the
asset is not being proposed, for two reasons. First, it would create a
‘bright line’ that might encourage management to make business
decisions to achieve a desired accounting outcome (or discourage such
decisions). Secondly, the shift between measurement bases would lead to
changes in the measurement of the asset that are not related solely to the
changes in the economic attributes of the asset. For example, if the
measurement basis of an asset changed from historical cost to fair value
when development starts, the change in the asset’s measurement would
be a combination of the value attributable to the start of development and
the value attributable to the asset that was not previously captured in the
asset’s historical cost. Consequently, this would not provide a faithful
representation of the entity’s financial performance in the period when
the measurement basis changed.
4.78
The project team acknowledges that a decision to apply a consistent
measurement basis across all exploration properties and minerals or oil
and gas properties will influence which measurement basis is selected for
these assets. This is because the measurement basis would need to be
capable of providing useful information for all assets, whether those
assets are exploration properties or minerals or oil and gas properties.
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Income recognition
4.79
The decision to use historical cost or current value as the measurement
basis has significant implications for income recognition. The current
practice of measuring mineral properties at historical cost means that
income is generally recognised at the point when revenue is recognised
for the sale of the extracted minerals or oil and gas to a third party. It also
means that income related to a specific unit of production is generally
recognised only once. (If a reserve is impaired but the minerals or oil and
gas are subsequently produced and sold, then income may be affected
more than once.) In contrast, a current value measurement basis means
remeasuring the asset each reporting period. The difference in the
current value is accounted for in income. (This might be in profit or loss,
or in other comprehensive income.)
4.80
This has two implications for the comprehensive income statement.
First, income will be recognised earlier under a current value model than
under a historical cost accounting model. For example, ore containing
copper is extracted from a mine and is processed through a concentrator
to separate the copper from the other (mainly waste) content of the ore.
The concentrate may then be stored at the mine for a period of time until
it is shipped to a customer. Under a historical cost accounting model,
income is generally recognised when the concentrate is shipped. Under
a current value accounting model, income would be recognised initially
when the current value of an exploration property or a minerals or oil
and gas property exceeds its cost. Income (or losses) would be recognised
in subsequent periods when the current values of those assets change
because of new information or changes in economic conditions, when the
ore is extracted (since the current value of the ore would be greater than
that of the mineral in the ground), and when concentrate is produced.
In contrast to a historical cost accounting model, the income recognised
when the concentrate is shipped might be quite small, since most of the
income would have been recognised earlier. (The total income recognised
under each measurement basis is, of course, the same.)
4.81
The second implication is the potential for volatility of reported income.
Over the life of a mine (or oil and gas field) the relevant commodity price
may go through one or more cycles of increases and decreases.
The fluctuations (together with changes in other assumptions) will cause
the current value of the mine also to fluctuate, with year-on-year
increases or decreases in current value reported in income. This would be
similar to the impact of measuring financial instruments at fair value.
The volatility resulting from measuring operating assets such as minerals
or oil and gas properties at fair value is often viewed by preparers as
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reducing the relevance of the statement of comprehensive income and
masking current performance. Proponents of current value, on the other
hand, argue that the statement of comprehensive income is reflecting the
real-world volatility and thus providing a more faithful representation of
the entity’s financial performance. However, the faithful representation
of financial performance depends on the estimate of the current value of
the minerals or oil and gas properties also being representationally
faithful—the current value may change because of estimation changes for
the inputs used to determine the current value rather than because of
changed facts and circumstances.
4.82
Using a different form of current value measurement such as a
standardised measure would also have additional implications for the
statement of comprehensive income. For example, the year-end price for
oil may change significantly from one year to another and the impact of
that change would be reflected in income. However, the long-term
expectation for prices may not have changed as much, and so the change
in value of the asset would be less than the amount recorded in income.
Similarly, if only proved reserves are measured then an increase in proved
reserves, and (in many cases) a corresponding reduction in probable
reserves, will have a disproportionate effect on income, even though the
entity’s best estimate regarding the total quantity of oil that may be
produced may not have changed. Furthermore, a reduction in proved
reserves would have the same effect on income regardless of whether
there is a corresponding increase in probable reserves (as per above) or if
those reserves were no longer expected to be produced. Accordingly, the
simplifications in a standardised measure may distort reported income.
Project team’s view on measurement
4.83
The research does not provide substantive support for either historical
cost or fair value as the measurement basis for exploration properties and
minerals or oil and gas properties. Historical cost generally does not
provide relevant information. Fair value conceptually provides relevant
information.
However, owing to the subjectivity and degree of
estimation involved, users do not view entity-prepared current values as
being representationally faithful, and therefore they would make limited
use of them. In the project team’s view, information that is not used is
not relevant. Preparing current value estimates of these assets involves
significant work effort and cost. The project team thinks that measuring
these assets at current value would not meet a cost-benefit test. For the
reasons discussed above, the project team also does not support
measuring the assets in the financial statements at a current value
similar to a standardised measure.
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4.84
This might suggest that all exploration, evaluation and development
expenditures should be recognised as expenses. However, this would
seriously misstate the statement of comprehensive income because
expenditures that result in future value to the entity would negatively
affect income. It would also result in not recognising assets of the entity.
An entity that found and developed a minerals or oil and gas property would
show negative income until production began. This cannot be considered
faithfully representational. The use of historical cost as the measurement
basis would address these issues. The statement of comprehensive income
would not be negatively affected by expenditures that create or increase
the value of assets. Assets would be recognised in the statement of
financial position, although this would be at amounts that are not relevant
to most users. Historical cost is also a less costly measurement basis for
preparers, although existing historical cost practices have developed over
many years and are sometimes more complex than they need to be.
If historical cost remains the measurement basis for exploration
properties and minerals or oil and gas properties, the project team
believes a single approach should be developed and that, given the
limited relevance of historical cost, one of the principles of that approach
should be simplicity. In other words, a historical cost accounting model
for these assets should not be complicated by detailed and prescriptive
cost allocation and requirements to capitalise or recognise as expense.
However, the project team acknowledges that the historical cost
measurement of these assets would need to be subject to depreciation
calculations and impairment testing.
4.85
The project team acknowledges that its choice of historical cost as the
measurement basis is based to a large extent on doing the ‘least harm’,
and may not meet the objective of financial reporting of providing
financial information that is useful for making decisions. The one clear
finding is that for financial statements to provide useful information
about exploration properties and minerals or oil and gas properties—the
core assets for entities engaged in extractive activities—substantive
disclosures about the reserves would be required. This is true whether
the measurement basis is historical cost or current value. As discussed
above, the historical cost of a minerals or oil and gas property does not
provide relevant information and thus would have to be supplemented by
disclosures. With a current value, users would require disclosure of the
main assumptions so that they could evaluate the current value or to
adjust it to be consistent with their own assumptions. Disclosures are
discussed in Chapter 5.
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Chapter 5 – Disclosure
Introduction
5.1
The research project’s user survey found that the primary sources of
information that users rely on when analysing an entity’s minerals or oil
and gas properties are financial statement disclosures and other
disclosures, such as management commentary or regulatory filings,
rather than the statement of financial position, statement of
comprehensive income or the statement of cash flows.
5.2
On the basis of those findings, this chapter identifies the general features
of a disclosure model for extractive activities, including:
(a)
a disclosure objective for extractive activities; and
(b)
the types of disclosure necessary to satisfy this objective over and
above the disclosures required by existing IFRSs, such as the
disclosure of significant accounting policies and the disclosures
required by IAS 36 Impairment of Assets.
A disclosure objective for extractive activities
5.3
5.4
The objective of general purpose financial reporting is to provide external
users with information that is useful in making economic decisions.
Disclosure can provide such information by:
(a)
amplifying the information that is presented in the financial
statements; or
(b)
providing information additional to that contained in those
statements.
In making informed economic decisions about entities in the extractive
industries users need information about the main drivers of cash flows—
the minerals or oil and gas reserves. Information about those reserves is
also necessary in determining whether the directors and management
have made efficient and profitable use of the financial and other
resources entrusted to them. Given the limited relevance that users
attach to the recognition and measurement of minerals or oil and gas
properties in the statement of financial position, a disclosure objective
for extractive activities should focus on providing additional information
about these assets that is useful for making decisions and evaluating
directors’ and management’s stewardship of the entity.
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5.5
In the project team’s opinion, the disclosure objective for extractive
activities should be to provide additional information that can enable
users to evaluate:
(a)
the value attributable to an entity’s minerals or oil and gas
properties;
(b)
the contribution of those assets to current period performance;
and
(c)
the nature and extent of the risks and uncertainties associated
with those assets.
Evaluating value
5.6
The cash flows that will result from the extraction of the minerals or oil
and gas are the most significant driver of value for upstream operations
and are crucial to any evaluation of entities in the extractive industries.
Disclosure of information about the quantity of the reserves is important
for users to be able to estimate the value of an entity’s minerals or oil and
gas properties and the future cash flows that might be generated from
those properties.
5.7
As discussed in Chapter 4, users generally do not think it useful to
measure minerals or oil and gas properties at fair value or at some other
form of current value for financial statement purposes. This applies
whether this information is provided in the statement of financial
position or in the notes to the financial statements. Rather than relying
on a valuation provided by management, users view it as important to
develop their own valuation based on the assumptions that they see as
being most appropriate. However, some inputs to their valuation, such as
the quantities of reserves and resources, can come only from the entity,
and the views of the entity’s management on other factors can also be
very helpful. Users therefore require disclosure of information that is
needed either as direct input to their valuation or to help them develop
that input.
5.8
Some users that analyse entities in the oil and gas industry said that they
find the disclosure of a current value measurement (such as the
standardised measure of proved oil and gas reserves required by FASB
ASC paragraph 932-235-50-30*) useful in helping them develop inputs for
their own valuations.
*
This disclosure requirement was introduced into US GAAP by SFAS 69 Disclosures about Oil
and Gas Producing Activities.
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Evaluating performance
5.9
5.10
Financial statements (including disclosures such as segment disclosures)
normally provide useful information for assessing current period
financial performance of an entity. Information in financial statements
that helps users evaluate the current period financial performance of an
entity engaged in extractive activities may include:
(a)
revenues from the sale of minerals or oil and gas and the costs of
production;
(b)
exploration, evaluation and development costs that have been
recognised as expenses; and
(c)
exploration, evaluation and development costs that have been
capitalised.
However, particularly for entities engaged in extractive activities,
performance is also assessed by using non-financial information to
determine how well an entity is managing its minerals or oil and gas
properties. This information includes the quantity of minerals or oil and
gas that has been produced, new discoveries of minerals or oil and gas,
and changes in the estimate of reserve quantities.
Evaluating risk and uncertainty
5.11
Extractive activities are subject to significant risks and estimation
uncertainties. Users should therefore be provided with sufficient
information to understand the nature and extent of the main risks and
estimation uncertainties associated with minerals and oil and gas
properties. This includes:
(a)
expressing estimates of recoverable quantities of minerals or oil
and gas at different confidence intervals (eg proved reserves,
probable reserves);
(b)
presenting these estimates separately for properties that are
subject to different risks, such as market risks and political risks;
(c)
disclosing the main assumptions associated with these estimates
and sensitivity analysis of those assumptions; and
(d)
providing explanations of changes in these estimates from year to
year.
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Guiding principles relevant to the disclosure objective
5.12
Chapter 1 sets out the parameters that were applied to the research into
financial reporting issues for extractive activities. The following
paragraphs consider how two of those parameters—relating to common
requirements across the minerals and oil and gas industries and the
scope of financial reporting—should apply to disclosures.
Common disclosure requirements
5.13
5.14
In developing common disclosure requirements, the objective is that the
same types of information should be disclosed across the minerals and oil
and gas industries in relation to extractive activities. The justification for
common disclosure across the two industries is that:
(a)
users’ needs in both industries are similar—the user survey found
that users’ information needs are driven by their interest in
predicting future cash flows under conditions of geological and
economic uncertainty; and
(b)
the report prepared by the expert industry working group (as
discussed in Chapter 2) indicated that geological and economic
uncertainty associated with minerals or oil and gas deposits can be
analysed and described in a consistent manner, as shown by the
working group’s conclusion that the definitions of minerals and oil
and gas reserves are broadly comparable.
This justification for common disclosure is not meant to imply that the
information that is disclosed should necessarily be identical across both
industries. Rather, it means that the information that is disclosed should
be the same within each industry and broadly comparable across the
minerals and oil and gas industries. Specific characteristics of the
different industries will, in some cases, require some variation in the
form and content of the disclosures; but the type of information disclosed
will be consistent across both industries.
Scope and constraints of financial reporting
5.15
It is not the intention of financial reporting to meet all of the information
needs of users, nor would it be possible. The Framework acknowledges
that, although financial reporting is primarily directed to meeting the
needs of capital providers, it is not the only source of information that
capital providers will rely on when making their investment decisions.
It states at paragraph OB15 that these users ‘also need to consider
pertinent information from other sources, for example, information
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about general economic conditions or expectations, political events and
political climate, and industry and company outlooks. Users also need to
be aware of the characteristics and limitations of the information
provided by financial reports.’ Consequently, in the context of disclosure
of information about extractive activities, consideration needs to be
given to whether the proposed disclosures should be provided in the
notes to the financial statements or elsewhere. This might include
management commentary and other types of communication such as
fact books, annual reviews, quarterly production reports. It might also
include other types of reporting that address corporate social
responsibility and sustainability matters.
5.16
Consistently with the research approach outlined in Chapter 1, the
project team’s proposals include disclosures that:
(a)
help users of financial reports to make decisions;
(b)
can reasonably be viewed as being within the scope of a complete
set of financial statements; and
(c)
meet a cost-benefit test.
Existing disclosures
5.17
Many entities already provide extensive disclosures about minerals or oil
and gas reserves, including disclosures that are similar to proposals in this
discussion paper. Those disclosures may be made as a result of regulatory
requirements or on a voluntary basis because entities see them as good
practice. Because of these existing disclosure practices, some may regard
disclosures about minerals and oil and gas reserves as a matter for
securities regulation rather than for accounting standards. The project
team does not agree. As discussed earlier in this chapter, disclosure of
reserve information is central to meeting the objectives of financial
reporting. It can be argued that the extent of the current regulatory
requirements is necessary because of the absence of any similar disclosure
requirements in IFRSs. Somewhat similar disclosures are already required
under IFRSs for biological assets. IAS 41 Agriculture, at paragraph 46, states
that an entity shall describe non-financial measures or estimates of the
physical quantities of its biological assets at the end of the reporting period
and the output of agricultural produce during the period.
5.18
There is currently no single set of disclosure requirements
internationally. Consequently there is wide variation in the quantity and
type of information disclosed, as well as in how that information has
been compiled (including the assumptions that were used in any
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estimates) and presented. This can make it difficult for users to analyse
and compare entities. Including these disclosures in an IFRS is the most
effective way to achieve internationally consistent reporting of
information on minerals and oil and gas reserves.
Duplication of disclosures
5.19
There are some differences between the disclosure proposals presented in
the discussion paper and existing disclosure requirements established by
certain regulators. As a result, concerns have been raised that the project
team’s disclosure proposals could lead to an IFRS that requires the
disclosure of information that is inconsistent with, or duplicates,
regulatory requirements. This would impose additional preparation
costs on preparers and potentially confuse users. Nevertheless, the
project team is of the view that the research should not be constrained by
existing regulatory requirements, just as the team is not constrained to
be consistent with existing IFRSs in arriving at its proposals. The project
team expects that, during the development of an IFRS, there would be
discussions between the IASB and regulators about avoiding
inconsistencies and duplication of disclosure requirements. A related
issue is that preparers currently use established processes to comply with
regulatory requirements and even subtle changes could result in
significant systems changes. Thus, from a cost-benefit perspective,
including some existing regulatory disclosure requirements in an IFRS
may be preferable to establishing similar but different disclosures.
Audit implications
5.20
Information that is presented in the financial statements (including
financial statement note disclosures) is generally subject to assurance
processes (ie audit) and responsibility for that information is usually
clearly defined (ie in terms of the relative responsibilities of directors,
managers and auditors). Although IFRSs set the requirements for the
content of the financial statements and the notes, the assurance of that
financial reporting information is prescribed by regulatory or stock
exchange listing requirements in individual jurisdictions.
5.21
A consequence of disclosing reserve information in the financial
statements is that those disclosures would be subject to the same degree
of assurance as other financial reporting information. Many industry
participants are concerned that auditing the disclosure of reserves
information would be very costly and that there is a lack of appropriately
qualified independent consultants to perform those audits within the
time frame for preparing and publishing financial reports.
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5.22
The survey of users found that many did not think that an independent
audit of the reserves information was necessary. They also suggested that
the cost of the audit could be prohibitive and that the degree of
imprecision and subjective assessments that are required in estimating
reserves would mean that an independent review might not greatly
enhance the usefulness of the information reported. Many users thought
that requiring the estimates to be prepared by a suitably qualified and
experienced professional would be sufficient. (This is discussed further in
paragraph 5.49.)
5.23
On the basis of these findings, the project team thinks that requiring
disclosure of audited reserves information would not meet a cost-benefit
test (and might be impractical). However, information on mineral and oil
and gas reserves is of great importance to users of financial reports and
the project team thinks that an IFRS should require the disclosure of
reserves information. Therefore, to overcome those audit concerns, the
project team recommends that an IFRS should require the disclosure of
this information on a basis similar to IAS 41’s requirement to disclose
physical quantities of biological assets. IAS 41 says that the disclosure of
that information is not required in the notes to the financial statements
if it is disclosed elsewhere in information published with the financial
statements. The project team thinks that this approach should ease
concerns about the audit implications of an IFRS requiring these types of
disclosure. The FASB made a similar decision on the location of oil and
gas disclosures within a financial report when setting its disclosure
requirements. Paragraph 116 of the Basis for Conclusions on SFAS 69
Disclosures about Oil and Gas Producing Activities states:
… In addition, cost-benefit considerations (as well as reliability
considerations) indicate that information about the reserve quantities,
estimated discounted future net cash flows, and results of operations should
be supplementary because the placement of information outside the
financial statements may result in lower auditing costs.
Disclosures
5.24
The types of disclosure that would satisfy the disclosure objective are
summarised in Table 5.1. The project team acknowledges that these
proposed disclosures are extensive, but nevertheless regards them as the
minimum disclosures that should be provided to enable users of financial
reports to make informed investment decisions about minerals and oil
and gas entities engaged in extractive activities. Entities may wish to
provide further information in their financial reports beyond these
disclosures proposed by the project team.
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Table 5.1 – Disclosure proposals
1
Disclosure type Information to disclose
Level of detail
Reserve
quantities
• By commodity,
and further
broken down by
country or
project (where
material)
• Proved reserves and
proved and probable
reserves
• Estimation method
• Main assumptions
• Sensitivity analysis to
main assumptions
• Reconciliation of changes
in reserve quantities
2A
Current value • Option A: Range of
estimates of fair value
measurement
(if asset is
• Option B: Standardised
measured at
measure of proved and
historical cost)
probable reserves
• Generally
disclosure by
major
geographical
region
• Preparation basis
• Main assumptions
• Reconciliation of changes
in current value
2B
Fair value
measurement
(if asset is
measured at
fair value)
• Fair value estimate
• Main assumptions
• Sensitivity analysis to
main assumptions
• Generally
disclosure by
major
geographical
region
• Reconciliation of changes
in reserve values
• Other disclosures similar
to the proposals in the
exposure draft Fair Value
Measurement
continued...
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...continued
5.25
Disclosure type Information to disclose
Level of detail
3
Production
revenues
•
Production revenues
•
By commodity
4
Costs
•
Exploration costs
•
•
Development costs
Disaggregated
as per reserve
quantities
•
Production costs
•
Time series of
disclosure over
five years
Disclosure types 1, 3 and 4 should be provided regardless of whether the
minerals or oil and gas property is measured at historical cost or at fair
value.
In addition to these disclosures, the project team is
recommending:
(a)
separate presentation of the carrying amounts of assets relating to
properties in production, other properties with reserves that are
not in production, and exploration properties (see Chapter 3); and
(b)
disclosure of management’s views on the recoverability of its
exploration properties for the purposes of impairment testing—
assuming those exploration properties are measured at historical
cost (see Chapter 4).
Disclosure type 1: Reserve quantities
Categories of reserves to be disclosed
5.26
Information about the quantities of mineral or oil and gas that an entity
expects to be able to economically recover is critical to understanding that
entity’s financial position, and therefore its ability to generate future cash
inflows. Typically these quantities of minerals or oil and gas would be
classified as reserves. As discussed in Chapter 2, the project team considers
that the CRIRSCO Template and the PRMS should be used to define reserves
and resources for the purposes of financial reporting. Under these
definition systems, the minerals and oil and gas reserves classification
includes the categories of proved reserves and probable reserves.
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5.27
Of the users surveyed, most said that the disclosure of proved and
probable reserves is the minimum level of information that should be
provided on minerals or oil and gas quantities. The project team notes
that proved and probable reserves is generally the focus of the
management of the business of entities engaged in extractive activities.
5.28
The project team therefore proposes that entities should disclose proved
reserves and, separately, the sum of proved and probable reserves. Those
disclosures would provide users in both industries with comparable
information—namely, a high confidence estimate and the best estimate
of economically recoverable quantities of minerals or oil and gas.
The project team acknowledges that this would represent an increase in
the amount of reserve disclosure provided by many oil and gas entities.
This includes all SEC registrants that, until 2009, have been prohibited
from disclosing reserve quantities other than proved reserves in their
annual reports. A revised SEC rule now permits, but does not require,
entities to disclose probable reserves and possible reserves.*
5.29
Some entities may also wish to disclose information beyond proved and
probable reserves. Many entities in the minerals industry currently
disclose resources as well as reserves.† The disclosure of possible reserves
for oil and gas or inferred resources for minerals provides users with an
indication of upside potential. The disclosure of mineral resources or
marginal contingent petroleum resources provides information on the
quantities of minerals or oil and gas that are attributable to potential new
projects or potential extensions to existing projects. How useful this
information is depends in part on the size of the entity and on the
maturity of its projects. For many large entities, upside potential beyond
proved and probable reserve may not be the primary focus of a user of
financial reporting when making an investment or lending decision
about the entity. In part, this reflects a general view among many users
that large minerals or oil and gas entities should usually be capable of
replacing reserves through either finding and developing new properties
or acquiring interests in existing properties. However, for many smaller
entities, information about resources could significantly influence
investment decisions because resources are their primary asset.
Consequently, the disclosure of resources information by these entities
would also be consistent with the disclosure objective identified in
paragraph 5.5 above.
*
The disclosure of oil and gas resources (referred to as contingent resources in the PRMS
definitions) is still prohibited under the SEC rules.
†
SEC registrants are prohibited from disclosing resource information unless it is
required to be disclosed by another jurisdiction.
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5.30
Some commentators, primarily in the oil and gas industry, do not support
the disclosure of probable or possible reserves or resources. They are
concerned that some users may be misled if they do not understand the
risks and uncertainties associated with these reserve and resource
estimates. They are also concerned that this might give rise to litigation
risks. The project team does not support limiting the disclosure
requirements to proved reserves in order to address these concerns. This
is because users would be denied useful information that could otherwise
be applied in their investment decision-making. The Framework assumes
that users will exercise reasonable diligence when analysing financial
reporting,* and the project team thinks the reserve and resource
definitions are helpful in communicating to users the level of
uncertainty associated with the estimate through the use of
classifications such as proved reserves and probable reserves. The project
team considers that concerns about uncertainties associated with reserve
and resource estimates can be mitigated by including a brief definition of
each reserve classification as part of the reserves quantity disclosure.
Reserves attributable to the entity
5.31
*
The reserves that are attributable to an entity are those quantities of
minerals or oil and gas that an entity has the enforceable right to extract.
In some jurisdictions, the taxation or royalty arrangements that apply to
the production of minerals or oil and gas may be payable in cash (eg the
tax or royalty may be levied on the revenue from production) or in kind
(eg the entity may be required to deliver a portion of production
quantities direct to the government or royalty owner). Under some other
royalty arrangements, the entity may be required to purchase the royalty
quantity at the point of production because the government or royalty
owner does not have the ability to market the quantity. These various
royalty arrangements differ in form but the underlying substance of each
type of arrangement is effectively the same in that the entity is obliged by
the arrangement to make a payment to the government or royalty owner
in exchange for the entity’s rights to extract the minerals or oil and gas.
The project team thinks that, in principle, all these arrangements should
be accounted for consistently. Consequently, each type of payment
should be treated as an expense of the entity regardless of whether the
cost is denominated in cash or in kind. As such, the financial statements
IASB Framework paragraph QC35
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should present production revenues and the tax or royalty expenses
separately—and consistently with this, the underlying reserve quantities
that are controlled by the entity should be included in the reserve
quantities disclosed by the entity.
5.32
An entity may have subsidiaries, interests in joint arrangements, equity
accounted investments and other investments that themselves have
reserves. There is a question whether some or all of those reserves should
be included in an entity’s required disclosures. The project team’s view is
that an entity should be required to disclose the minerals or oil and gas
reserve quantities it controls.* The basis for disclosure of these reserve
quantities should be consistent with the accounting approach used by the
entity in its consolidated financial statements for the assets held through
each such investment.
5.33
Accordingly, the reserves required to be disclosed should include reserve
quantities attributable to the parent entity, to its subsidiaries, and to its
interests in joint arrangements that are not equity accounted. Reserves
held by equity accounted or cost accounted investees should not be
included as part of those quantities (but might be separately disclosed—
see paragraph 5.34). This may represent a change to existing disclosure
practices, because the existing practice in identifying the reserve
quantities varies depending on the jurisdiction and the industry. Current
practices include identifying:
(a)
*
the reserve quantities that are attributable to the entity in
accordance with its equity or ownership interests in the entity or
assets that have the reserves (see exhibit 5.1, which shows that
Lonmin plc’s disclosed reserves include only the portion
attributable to Lonmin);
Control is defined in IAS 27 Consolidated and Separate Financial Statements as ‘the power to
govern the financial and operating policies of an entity so as to obtain benefits from its
activities’.
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Exhibit 5.1
Mineral Reserves (Total Proved & Probable)
30-Sep-2008
Mt
3PGE+AU
Area
Pt
g/t
Moz
Moz
Marikana
332.6
4.03
43.1
25.9
Limpopo
40.1
3.23
4.2
2.1
Limpopo Baobab shaft
9.4
3.16
1.0
0.5
0.46
4.28
0.06
0.04
382.5
3.93
48.3
28.5
Pandora JVc
Total
All quoted Resources and Reserves includes Lonmin’s attributable portion only
and the following percentages were applied to the total Mineral Resource and
Reserve for each property:
Area
Marikana
Limpopo –
Dwaalkop
JV
Limpopo –
Doornvlei,
Zebedelia,
Baobab
Pandora
82%
41%
82%
34.85%
Lonmin Attributable
Edited extracts from Lonmin Plc, 2008 Annual Report and Accounts, page 11
(b)
100 per cent of the reserves attributable to consolidated subsidiaries,
with the non-controlling interests in the reserves that are
attributable to partly-owned subsidiaries that form part of the
consolidated group also identified where material (see exhibit 5.2); or
Exhibit 5.2
PROVED DEVELOPED AND UNDEVELOPED
RESERVES 2008
Europe Africa
million barrels
AsiaPacific
Middle
East,
Russia,
CIS
USA
Other
Americas
Total
Shell
subsidiaries
At January 1
Revisions and
reclassifications
615
567
158
908
375
128
2,751
13
107
6
180
35
(46)
295
continued...
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...continued
PROVED DEVELOPED AND UNDEVELOPED
RESERVES 2008
million barrels
Improved
recovery
–
31
–
23
–
–
54
Extensions and
discoveries
9
4
6
14
7
–
40
Purchases of
minerals in place
–
–
–
–
–
4
4
Sales of minerals
in place
(21)
(4)
(2)
(36)
(1)
–
(64)
(135)
(113)
(32)
(85)
(69)
(26)
(460)
481
592
136
1,004
347
60
2,620
26
–
190
482
297
30
1,025
(14)
–
10
(16)
(27)
(6)
(53)
Improved
recovery
–
–
–
–
–
–
–
Extensions and
discoveries
–
–
1
9
1
–
11
Purchases of
minerals in place
–
–
–
–
–
–
–
Sales of minerals
in place
–
–
(1)
–
–
–
(1)
Production
(2)
–
(43)
(80)
(30)
(4)
(159)
At December 31
10
–
157
395
241
20
823
Minority interest
in reserves of
Shell subsidiaries
At December 31
–
8
–
–
–
–
8
Production
At December 31
Shell share of
equity-accounted
investments
At January 1
Revisions and
reclassifications
Edited extracts from Shell Annual Report and Form 20-F 2008, page 162
(c)
100 per cent of the reserves attributable to the property (or,
possibly, a group of properties) with the share attributable to the
entity shown separately (see exhibit 5.3).
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Exhibit 5.3
Type of
mine (a)
Proved ore
reserves
at end 2008
Tonnage
Probable ore
reserves
at end 2008
Grade Tonnage
Total ore reserves 2008
compared with 2007
Grade
Tonnage
2008
millions %AI2O3
of
tonnes
BAUXITE
2007
Rio Tinto share
Grade Interest Recoverable
2008
2007
%
millions %AI2O3 millions millions %AI2O3 %AI2O3
of
of
of
tonnes
tonnes tonnes
mineral
millions
of
tonnes
Reserves at
operating
mines
Gove
(Australia)
O/P
111
49.5
64
49.0
175
143
49.4
49.2
100.0
175
(Brazil)
O/P
147
50.8
59
50.1
205
166
50.6
51.2
12.0
25
Sangaredi
(Guinea)
O/P
133
52.4
133
–
52.4
–
23.0
30
Weipa
(Australia)
O/P
1,398
52.6
1,736
1,224
52.4
53.6
100.0
1,736
Porto
Trombetas
(MRN)
337
51.5
Total
1,966
Edited extracts from Rio Tinto Annual Report 2008, page 112
5.34
Disclosure of reserves quantities beyond those that are controlled by the
entity may be appropriate to the extent that this information is
important to users in making their investment decisions. Accordingly,
subject to the information being material, the reserve disclosure could
extend to including the disclosure of reserves attributable to:
(a)
investments that are equity accounted, such as investments in
associated entities that are under the significant influence, but not
the control, of the entity and are accounted for under IAS 28
Investments in Associates; and
(b)
investments that are shareholdings and accounted for under IAS 39
Financial Instruments: Recognition and Measurement.
Any such disclosure should be separate from the disclosure of the reserves
controlled by the entity and make clear the nature of the entity’s interest
in the reserves. This would also include the separate identification of the
reserves that are attributable to non-controlling interests. Exhibit 5.2
illustrates how this distinction can be presented.
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5.35
In accounting for joint arrangements, the IASB has tentatively decided to
remove proportionate consolidation as an available accounting choice in
IAS 31 Interests in Joint Ventures. The IASB, in its redeliberations on ED 9 Joint
Arrangements, has tentatively decided that arrangements that are jointly
controlled entities under IAS 31 should be assessed to determine whether
they are joint operations or joint ventures. If the entity does not have
interests in the assets and liabilities arising from the joint arrangement,
then the joint arrangement is classified as a joint venture that is to be
accounted for under the equity method. The IASB’s proposals on
accounting for joint arrangements could therefore have implications for
an entity’s reserves quantity disclosures under the project team’s
proposals (as outlined in paragraph 5.32 above) because the reserves
attributable to joint ventures could not be attributed to the entity. This
is because they are not reserves that are controlled by the entity. (For a
joint arrangement that is not equity accounted the entity includes its
share of the reserves of the joint arrangement in its reported reserves—see
paragraph 5.33.)
Reserves attributable to risk-sharing arrangements
5.36
In some jurisdictions the legal rights that an entity holds are rights to
cash flows based on the quantity of minerals or oil and gas produced
rather than on rights to the actual production. Production sharing
contracts (PSCs) in the oil and gas industry are common examples of these
types of rights, although there are also other risk-sharing arrangements
with similar features that exist in both industries.
5.37
Despite the nature of these contractual rights being different from
leasehold or concessionary rights, there are some similarities in the
economic substance of the rights. The presence and estimated quantity
of economically recoverable minerals or oil and gas may be an important
determinant of the future cash flows expected from either leasehold
rights or PSCs. However, PSCs are commonly designed to permit the
entity to recover finding, development and production costs, plus a
reasonable profit, while limiting the entity’s ability to benefit from
increases in prices (and similarly limiting the impact of price decreases so
long as development and production of the property remains economic).
This is accomplished by reducing the entity’s proportion of the cash flow
as prices increase so that most or all of the increase in cash flow is
received by the government or other leaseholder. This feature of PSCs is
significantly different from most other leasehold rights that are subject
to royalties or taxes based on production quantities, production revenue
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or income from production. The difference is that for most other
leasehold rights the benefit to the entity from the increase in prices
would generally be expected to be approximately in proportion to the
price increase.
5.38
It is common for an entity that is party to a PSC to apply its share of cash
flows to the total reserves and report the resulting number as part of its
reserves. This results in the seemingly anomalous situation of an entity’s
disclosed estimate of reserve quantities decreasing when prices go up.
The price change does not change the economic substance of the
arrangement—the entity is still able to recoup its costs and earn a profit,
but it needs fewer barrels of oil to do so. The terms of the PSC results in
the entity receiving a smaller proportion of the (increased) cash flows and
consequently reporting a smaller reserves number. This outcome is
acknowledged in BG Group plc’s 2008 Annual Report, which states
‘Increases in year end gas and oil prices in fields subject to Production
Sharing Contracts (PSCs) may result in lower entitlements leading to
reductions in proved reserves’.*
5.39
For these reasons, the project team advocates the separate identification of:
(a)
reserves attributable to PSC arrangements; and
(b)
reserves attributable to other types of taxation or royalty regimes
based on risk-sharing. This is considered further in the context of
disaggregated disclosures.
Disaggregated disclosure of reserve quantities
5.40
*
Not all reserve quantities are the same. The future cash flows and the
related risks and uncertainties that are attributable to a specific reserves
estimate depend on the type of commodity and the location—in terms of
its geological, geographical and geopolitical characteristics.
Disaggregated disclosure is needed to identify the reserves quantities that
are subject to different risks and uncertainties. Users may need some
reserves estimates to be presented at the individual property level.
For other reserves estimates that share common risks and uncertainties
or are individually immaterial, presentation at a higher level such as on
a country or regional basis may be sufficient to provide useful
information.
BG Group plc, Annual Report and Accounts 2008, Supplementary information—gas and
oil, page 115
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5.41
In the oil and gas industry in particular, reserve estimates are sometimes
calculated using probabilistic methods with the assessment performed at
the entity (ie portfolio) level or at some other level of aggregation rather
than only on a property basis. Proponents of this approach to reserves
estimation argue that it improves the precision of an entity-wide reserves
estimate because of the ‘portfolio effect’. However, estimating reserves
estimates with reference to the portfolio effect is inconsistent with the
objective of using disaggregated disclosure to identify the main risks and
uncertainties associated with specific reserves estimates.
Disaggregation by commodity type
5.42
Different commodities will have different future cash flows due to
differences in their prices. Different commodities will also usually have
different risks associated with them. This is particularly true for price
risk, with extraction and processing risks also being significant for some
commodities. It is therefore important for users to know reserves
quantities by commodity. As a practical matter it is normally not possible
to aggregate quantities of different commodities in a meaningful way.
Accordingly, reserve quantities should be disclosed separately for most
types of minerals and for oil, gas and oil sands.
5.43
Separate disclosure by commodity type is commonplace in the minerals
industry, with aggregation typically occurring only for some platinum
group metals such as platinum, palladium and rhodium. However, some
disclosure practices in the oil and gas industry involve aggregation by
commodity type whereby some entities disclose their oil and gas reserves
together on a barrel-of-oil equivalent (BOE) basis. Users have said that BOE
disclosures are inferior to the separate disclosure of oil quantities and gas
quantities because oil and gas are subject to different market risks. Some
users have also suggested that oil sands reserves should be disclosed
separately from oil reserves because the oil sands require much higher
operating costs to produce the oil than do conventional oil deposits.
However, some industry participants argue that separate disclosure of oil
sands quantities is not warranted because the oil from oil sands is sold
into the same market as oil from conventional deposits. The project team
acknowledges that the operating cost structure, and the consequent
financial risks of changes in costs and prices, might seem different from
those for conventional oil, but this is not necessarily so. A number of
offshore oilfields have significant capital costs. Other fields have major
transport costs or costs of injecting water or gaseous material to increase
pressure. There is thus a continuum from the traditional conventional
oilfield to those with high capital and operating costs. It is not practical
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to have separate disclosures about all different types of oilfields.
However, oil sands operations are clearly identifiable and are high cost
producers and, in the project team’s opinion, separate disclosure would
provide useful information if those operations were material to the
entity. Reserves attributable to other high cost operations should also be
disclosed separately, if material.
Disaggregation by geography
5.44
The disclosure of these quantities should be further disaggregated by
geographical location. This disaggregation should be determined on the
basis of different risks that are significant to the entity. Strictly speaking,
this would generally mean that separate reserve estimates should be
disclosed for each property to reflect the different geological risks that
are likely to be associated with each mine (and possibly even individual
pits) or field. This will not always be practical, especially in the oil and gas
industry where some large entities have as many as a thousand individual
properties. Consequently, some level of aggregated quantity disclosure
will often be necessary, particularly in the oil and gas industry.
Aggregated quantity disclosure is less relevant in the minerals industry
because of the generally smaller number of properties, and so existing
disclosure practice tends to be by property.
5.45
Geographical disaggregation of reserve quantities at a country level is
regarded as providing relevant information. This is because of the
significance and prevalence of risks that are country-specific (eg taxation
regime, legal and regulatory framework, governmental/sovereign risk).
However, country-by-country disclosure may not always be the most
useful aggregation basis.
Sometimes a more detailed level of
disaggregation should apply—for instance, disclosure by individual
properties or groups of properties within the same geological area would
be particularly relevant if the reserve quantities are of high significance
to the entity and if they involve substantially different geological or
operating risks. In other cases, less disaggregated disclosures may be
more relevant if they are based on geological boundaries rather than
political boundaries. An example might be the aggregation of North Sea
reserves as a single disclosure unit rather than potentially as separate
country-based disclosure units for, say, the Netherlands, Norway and the
United Kingdom. Furthermore, sometimes aggregation on a continental
basis may be appropriate, particularly if the reserve quantities
attributable to individual countries are of limited significance relative to
the entity’s total reserve position. The project team thinks that, within
these general parameters, management should use its judgement to
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determine the level of aggregation for its reserve disclosures. The level of
aggregation chosen should be treated as an accounting policy decision,
and therefore applied consistently from period to period. Any change in
the level of aggregation would represent a change in accounting policy
and would be subject to the requirements in IAS 8 Accounting Policies,
Changes in Accounting Estimates and Errors.
5.46
Many users in the minerals industry find that reserve and resource
quantity disclosures disaggregated on a property-by-property basis
provide useful information and so many entities in the minerals industry
provide such information. Accordingly, further consideration should be
given to whether property-by-property disclosure should be provided at
the discretion of the entity or if it should be specifically required in the
minerals industry to promote consistent and comparable disclosure in
that industry.
5.47
Because reserve quantities disclosures in the oil and gas industry are
often aggregated to a country level or higher, the disclosure may
separately classify the reserve quantities as ‘developed reserves’ or
‘undeveloped reserves’ according to the funding and operational status of
wells and associated facilities within the reservoir development plan.
The PRMS includes definitions for developed and undeveloped reserves.
Distinguishing between reserves that are developed and those that are
undeveloped helps users to assess the likely time frame for production of
the oil and gas reserves disclosed. In contrast, existing disclosure practice
in the minerals industry typically does not divide mineral reserves into
developed and undeveloped categories. It is less common in the minerals
industry because reserves are generally disclosed on a property-byproperty basis, and therefore users can readily see whether that property
is developed or undeveloped. The project team notes that the CRIRSCO
Template does not separately identify developed and undeveloped
reserves, although this classification exists as part of the United Nations
Framework Classification for Fossil Energy and Mineral Resources (which
is discussed in Chapter 2). The project team’s view is that the reserves
disclosure should be separately classified as developed reserves and
undeveloped reserves if there is not separate disclosure of reserves
quantities by individual property.
Basis of estimation
5.48
The method for estimating the reserves and resources quantities included
in financial statements should be disclosed. The quantities that are
disclosed should be estimated in accordance with generally accepted
industry practices that are consistent with the principles of the CRIRSCO
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Template and the PRMS. (One exception to this may be the selection of
economic assumptions to be used in estimating reserves. This is discussed
further in the section below.) Many minerals and oil and gas entities are
already providing this type of disclosure in their financial statements,
often in response to the requirements in paragraph 25 of IAS 1 to disclose
the source of estimation uncertainty. An example is presented below at
exhibit 5.4.
Exhibit 5.4
Reserve estimates
Reserves are estimates of the amount of product that can be
economically and legally extracted from the Group’s properties.
In order to estimate reserves, assumptions are required about a range
of geological, technical and economic factors, including quantities,
grades, production techniques, recovery rates, production costs,
transport costs, commodity demand, commodity prices and exchange
rates.
Estimating the quantity and/or grade of reserves requires the size,
shape and depth of orebodies or fields to be determined by analysing
geological data such as drilling samples. This process may require
complex and difficult geological judgements to interpret the data.
The Group determines and reports ore reserves in Australia and the UK
under the principles incorporated in the Australasian Code for
Reporting Exploration Results of Mineral Resources and Ore Reserves
December 2004, known as the JORC Code. The JORC Code requires the
use of reasonable investment assumptions when reporting reserves.
As a result, management will form a view of forecast sales prices, based
on current and long-term historical average price trends. For example,
if current prices remain above long-term historical averages for an
extended period of time, management may assume that lower prices
will prevail in the future and as a result, those lower prices are used to
estimate reserves under the JORC Code. Lower price assumptions
generally result in lower estimates of reserves.
continued...
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...continued
Reserve reporting requirements for SEC (United States of America)
filings are specified in Industry Guide 7, which requires economic
assumptions to be based on current economic conditions (which may
differ from assumptions based on reasonable investment assumptions).
Accordingly, for SEC filings, we test our reserve estimates derived under
JORC against assumed ‘current economic conditions’. ‘Current
economic conditions’ are based on the three-year historical average
contract prices for commodities, such as iron ore and coal, and the
three-year historical average for commodities that are traded on the
London Metal Exchange, such as copper and nickel. However, we only
report a different reserve in the US if, based on the US SEC pricing
assumptions test, the reserve will be lower than that reported under
JORC in Australia and the UK.
Oil and gas reserves reported in Australia and the UK, and the US for
SEC filing purposes, are based on prices prevailing at the time of the
estimates as required under Statement of Financial Accounting
Standards No. 69 ‘Disclosures about Oil and Gas Producing Activities’,
issued by the US Financial Accounting Standards Board.
Because the economic assumptions used to estimate reserves change
from period to period, and because additional geological data is
generated during the course of operations, estimates of reserves may
change from period to period. Changes in reported reserves may affect
the Group’s financial results and financial position in a number of
ways, including the following:
• Asset carrying values may be affected due to changes in estimated
future cash flows
• Depreciation, depletion and amortisation charged in the income
statement may change where such charges are determined by the
units of production basis, or where the useful economic lives of
assets change
• Overburden removal costs recorded on the balance sheet or
charged to the income statement may change due to changes in
stripping ratios or the units of production basis of depreciation
• Decommissioning, site restoration and environmental provisions
may change where changes in estimated reserves affect
expectations about the timing or cost of these activities
• The carrying value of deferred tax assets may change due to
changes in estimates of the likely recovery of the tax benefits
Edited extracts from BHP Billiton annual report 2009, Note 1 Accounting
policies, page 187
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5.49
Disclosures should also be made about the person who prepared the
estimate, including their qualifications and experience as an estimator.
The CRIRSCO Template requires that minerals reserve and resource
estimates be prepared by a ‘Competent Person’. This is a ‘person who is a
Member or Fellow of a recognized professional body relevant to the activity
being undertaken, and with enforceable Rules of Conduct’. The Society of
Petroleum Engineers’ Standards Pertaining to the Estimating and Auditing of Oil
and Gas Reserve Information makes reference to Reserves Estimators and
Reserves Auditors as being individuals with sufficient qualifications and
experience to perform those activities.
National regulators often
determine whether reserve quantities disclosures must be prepared by a
reserves estimator/reserves auditor or equivalent. Similar disclosures are
required by IAS 40 Investment Property and IAS 16 Property, Plant and Equipment
in relation to fair valuations of investment property and property, plant
and equipment. Specifically, IAS 40 requires the disclosure of ‘the extent
to which the fair value of investment property (as measured or disclosed in
the financial statements) is based on a valuation by an independent valuer
who holds a recognised and relevant professional qualification and has
recent experience in the location and category of the investment property
being valued. If there has been no such valuation, that fact shall be
disclosed.’*
Disclosure of the main assumptions
5.50
Reserve estimates are based on several assumptions and will often vary
widely depending on the assumptions used. It is therefore important that
the main assumptions used in the estimate should be disclosed. Similar
requirements exist in IAS 16, IAS 38 Intangible Assets, IAS 40, IAS 41 and the
exposure draft Fair Value Measurement proposals with respect to estimates
of fair value, which, if the income method is used, also involve the use of
several main assumptions.
Price assumptions
5.51
As discussed in Chapter 2, the CRIRSCO Template and the PRMS both
specify that the economic assumptions used in reserves and resources
estimation should be based on the entity’s internal forecasts of future
conditions.† However, there are a variety of views on whether the
economic assumptions used to estimate reserves for the purposes of
*
IAS 40 paragraph 75(e)
†
The PRMS indicates that management’s reasonable forecast is the base case assumption
for preparing reserve estimates. As an alternative to the base case, the PRMS also
permits the preparation of estimates based on current conditions.
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disclosing that information to external users should be management’s
own expectations or some other basis. The basis to be used for selecting
a commodity price assumption is particularly contentious, with the
following alternatives being commonly proposed:
5.52
(a)
a market participant assumption (akin to a Level 1 or Level 2 input,
as per the fair value measurement hierarchy outlined in Chapter 2);
(b)
management’s own expectations (a Level 3 input); or
(c)
a historical price such as the year-end spot price or an average of
past spot prices.
Most users surveyed want the reserve estimate to be based on a consistent
and objectively determined price assumption.
They indicated a
preference for a historical average commodity price for a defined trailing
period (eg the average price over the past 12 months). This averaging
eliminates the potential for disclosed reserve quantities to be based on a
single day’s price, which might be an aberration. A consequence of using
a standardised pricing assumption is that the disclosed reserves estimate
would not be the entity’s best estimate. Notwithstanding that, those
users suggested that a comparable price assumption is more important as
this would provide comparability for reserves data disclosed by different
entities. This view is shared by Standard and Poor’s in Oil And Gas Reserve
Reporting: Recommendations For Change of 29 November 2007, which
commented that:
Management should, of course, make long-term investment decisions based
on its estimates of similarly long-term oil and gas prices. However, using
anticipated future selling prices, rather than actual year-end amounts,
would reduce comparability and consistency. Reserves will likely vary based
on how bullish or bearish management is on prices. We therefore favor the
use of standard prices, such as average or year-end, to make figures
consistent and comparable among companies. Companies should disclose
selling prices by geographic area. The use of average prices may reduce
volatility caused by swings and seasonality in natural gas prices; year-end
prices may be more representative of year-end values. The ultimate solution
should require standardized selling prices and costs and allow additional
reserve disclosures at different prices (sensitivity analyses).
5.53
*
The SEC, in its revisions to the oil and gas reserves definitions and
disclosure requirements, requires the use of a 12-month average price,
calculated as the unweighted arithmetic average of the price on the first
day of each month within the 12-month period before the end of the
reporting period, unless prices are defined by contractual arrangements,
excluding escalations based upon future conditions.*
SEC Regulation S-X, Rule 4.10(a)(22)(v)
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5.54
The SEC noted that using expected future prices could require significant
estimation that could fall into a wide, although reasonable, range.
The SEC supported the use of historical prices by stating:
We believe that the purpose of disclosing reserves estimates is to provide
investors with information that is both meaningful and comparable.
The reserves estimates in our disclosure rules, however, are not designed to be,
nor are they intended to represent, an estimation of the fair market value of
the reserves. Rather, the reserves disclosures are intended to provide investors
with an indication of the relative quantity of reserves that is likely to be
extracted in the future using a methodology that minimizes the use of
non-reserves-specific variables. By eliminating assumptions underlying the
pricing variable, as any historical pricing method would do, investors are able
to compare reserves estimates where the differences are driven primarily by
reserves-specific information, such as the location of the reserves and the grade
of the underlying resource. We recognize that energy markets are continuing
to develop. Therefore, we are not adopting a rule that requires companies to
use futures prices to estimate reserves at this time.*
5.55
*
The use of standardised historical prices in reserves estimates prepared
for disclosure is also generally supported by entities in the oil and gas
industry, especially SEC registrants. This is shown by the responses made
to the SEC, and also in the project team’s consultations with preparers
from the oil and gas industry. In contrast, the use of historical average
price assumptions is not supported by most entities in the minerals
industry, where there is a strong preference to use management’s
forecast price assumptions. Those supporting the use of forecast price
assumptions note that management makes business and investment
decisions using expected future prices rather than current prices.
Accordingly, they argue that estimating reserves using expected future
prices provides a more faithful representation of the estimate than if
reserves were estimated using current prices. Many users have suggested
that in order to rely on a reserves estimate prepared using expected
future prices, it is important for that price forecast to be disclosed. This
raises a problem because many entities seem reluctant to disclose their
price assumptions, especially for commodities that are not
exchange-traded, on the grounds that this information is commercially
sensitive.
Preparers are concerned that disclosing their forecast
assumptions for commodity prices may prejudice the entity in future
asset sales or acquisitions or in negotiating contracts for the sale of its
production.
SEC Final Rule Modernization of Oil and Gas Reporting (Release No 33-8995), page 19
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5.56
The project team’s view is that faithful representation of reserves and
resources requires the use of forecast prices. The use of historical prices
risks misrepresenting the reserve quantities whenever the historical
price is not consistent with expected future prices. This is common in the
often volatile commodity markets. The project team accepts that the use
of forecast prices may result in some lack of comparability, to the extent
that different price assumptions are used by different entities. Concerns
about the potential lack of comparability can be reduced by providing a
consistent methodology for selecting the most relevant pricing
assumptions according to the individual facts and circumstances
associated with the reserves estimate. For this reason, as outlined in
Chapter 2, the fair value hierarchy should be applied to determine the
economic assumptions. The fair value hierarchy requires a Level 3 input
to be used only when a Level 1 or Level 2 input is not available.
5.57
The project team proposes that the pricing assumptions used in
estimating reserve quantities should be disclosed. If a price assumption is
a Level 3 input that is considered commercially sensitive, an exemption
from disclosing that assumption could be provided if the disclosure
would be expected to prejudice seriously the position of the entity.
A similar exemption is provided in IAS 37 Provisions, Contingent Liabilities
and Contingent Assets. This exemption usually applies in relation to
legal disputes and IAS 37 requires an entity making use of the exemption
to disclose the general nature of the dispute and explain the reasons
why it has not disclosed the information required. Therefore, if such an
exemption is provided, an entity that chooses to make use of the
exemption should be required to disclose the reasons why the price
assumption has not been disclosed.
Other assumptions
5.58
*
In principle, the main assumptions relating to the reserve estimate such
as discount rates, production profiles and cost assumptions should be
quantified as part of this disclosure. However, presentation problems
may make it more difficult to disclose these assumptions together with
the reserves estimate. This is because, for example, the discount rate,*
production profile and costs assumptions would usually be projectspecific, whereas commodity price assumptions may apply equally to
several or all of an entity’s projects.
The discount rate would be project-specific to the extent that it includes adjustments
for risk that relate to the individual project.
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5.59
Some oil and gas industry commentators have suggested that the
disclosure of a production schedule could be a substitute for disclosing
reserves quantities. The rationale is that the reserves are the quantities
of future production. It is suggested that the production schedule would
present annual production expectations for a defined period into the
future, such as five or ten years. Beyond such a period, the effect of the
discounting and the greater uncertainties with forecasting that far into
the future makes the production schedules less useful. The project team
is not proposing that a production schedule should be disclosed as a
substitute for, or to complement, the disclosure of reserves quantities.
The disclosure of annually updated production schedules was not
identified by many users as an important disclosure that they expected
could be justified on cost-benefit grounds. Instead, many users indicated
that they prepare their own production forecasts by taking into account
existing rates of production for operating mines and fields as well as
information on schedules for important development and production
milestones for mines or fields that are undeveloped or in development.
This schedule information can usually be obtained from entity
presentations and briefing updates for particular projects. Users typically
regarded this type of information, together with the disclosure of reserve
quantities (especially where the user can identify the quantities that are
attributable to properties in production, properties in development, and
undeveloped properties), as sufficient to prepare their own assessments
on the timing and amount of future cash flows.
Sensitivity analysis
5.60
A sensitivity analysis disclosure can be useful in helping to explain the
uncertainties associated with the reserves quantity estimate made as at
the reporting date. The project team recommends that a sensitivity
analysis disclosure should be provided to show the sensitivity of the
reserves quantity estimate to changes in the main economic
assumptions. The project team expects that this would usually mean
that, at a minimum, the sensitivity analysis would be based on changes to
the price assumption. Sometimes a reserves estimate will be more
sensitive to changes in other economic assumptions, such as
development or operating costs or exchange rates, in which case the
sensitivity should be based on changes in those assumptions.
5.61
A sensitivity disclosure would often need to take into account changes in
a number of economic assumptions if a complete assessment of the
sensitivity of reserves quantities to changes in the main economic
assumptions is to be provided. The disclosure of separate sensitivity
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analyses may be useful if changes in one of the main assumptions do not
directly affect changes in another assumption. In other cases, a single
sensitivity analysis may be more relevant if changes in one assumption
would be expected to have a consequential impact on various other
assumptions in a reserves estimate. For instance, changes in the
commodity price assumptions could have an impact on the assumptions
made about:
(a)
exchange rates in countries, such as Australia, where there is a
well-established correlation between the exchange rate and
commodity prices;*
(b)
development and production costs as a result of property-specific
factors, such as the optimal mine design to extract the minerals
economically or a decision to extract and process a higher
(or lower) grade; and
(c)
development and production costs as a result of industry or
economy-wide factors because, for instance, a high commodity
price environment can create demand for labour and equipment
that exceeds available supply.
Whether or not price sensitivity affects other assumptions depends partly
on whether the sensitivity is for a large price change or a small price
change. The following discussion assumes the price change sensitivity
has a significant effect on other assumptions. The determination of the
price change sensitivity is discussed in paragraphs 5.65–5.67.
5.62
*
Preparing a sensitivity analysis (eg for price) that includes the
corresponding impact on other assumptions would require new reserves
estimates to be developed. The project team does not think the benefits
from disclosing these comprehensive reserves sensitivities each reporting
period would justify the cost of preparing multiple reserves estimates for
each property. Another approach is to keep the other economic
assumptions constant. By keeping other assumptions constant, a reserves
sensitivity should be able to be disclosed with limited additional
preparation costs. However, this disclosure is less useful because it
ignores the consequential impact that the changes may have on other
assumptions. This is because, as noted above, there is not necessarily a
linear relationship between changes in commodity prices and changes in
reserve quantity estimates.
Hedge Funds in Emerging Markets, Gordon De Brouwer, Cambridge University Press 2001,
page 142. See also The Relationship Between Commodity Prices and the Australian Dollar by
John L Simpson from Curtin University of Technology - School of Economics and Finance.
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5.63
The project team prefers a compromise between these two approaches for
disclosing reserves sensitivities. The reserves sensitivity analysis should
include a reasonable estimation of how other assumptions might change
relative to changes in the main economic assumptions that are the
primary focus of the sensitivity analysis (eg the commodity price
assumption). Accordingly, the sensitivity analysis should take into
account the impact of changes that the entity should be able reasonably
to anticipate and quantify without requiring a detailed reassessment of
all components of the reserves estimate.
5.64
The project team recommends that an explanation of the sensitivity
analysis should accompany the disclosure. The explanation should
identify which economic assumptions are subject to the sensitivity
analysis, the other assumptions that change as a result of the sensitivity
analysis, and the assumptions that have been kept constant.
Sensitivity to the commodity price
5.65
This section considers some of the issues associated with preparing an
analysis of the sensitivity of the reserves quantity estimate to changes in
the commodity price. The sensitivity to the price assumption could be
determined in one of two ways. The sensitivity could be to an objectively
determined price change—such as the year-end or historical average
price, assuming that the entity’s reserves estimates are not based on these
assumptions. The benefit of showing the sensitivity to an objectively
determined price is that it can provide users with estimates of reserves
quantities that are prepared using a standardised pricing assumption
(as discussed earlier in this chapter). It would also help users to assess
the sensitivity of the reserves quantities (estimated using forecast
assumptions) to changes in current or recent commodity prices.
A reserves sensitivity disclosure similar to this is included in The SME Guide
for Reporting Exploration Results, Mineral Resources and Mineral Reserves
(September 2007);* but, the project team is not aware of any minerals
entities that are disclosing this type of reserves sensitivity.
5.66
Alternatively, the sensitivity could be to a percentage or incremental
change in the commodity price assumption. This type of sensitivity
disclosure can help users understand the potential impact on the entity’s
reserves estimates if a different view on commodity prices were adopted.
This type of sensitivity disclosure is provided by some gold mining
entities although the trend in disclosure is to move away from providing
*
Prepared by the Resources and Reserves Committee of the Society For Mining,
Metallurgy And Exploration, Inc
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this information. The PricewaterhouseCoopers 2008 gold survey of 45
gold mining and development entities found that only 31 per cent of
entities chose to disclose the sensitivity of reserves to price assumptions
in 2008 whereas 40 per cent of those surveyed entities had disclosed the
sensitivity in prior reporting periods. An example of this disclosure is
provided in exhibit 5.5 below.
Exhibit 5.5
Proven and Probable Equity Reserves
We had proven and probable gold reserves of 85.0 million equity ounces
as of December 31, 2008.
For 2008, reserves were calculated at a $725, A$850 or NZ$1,000 per
ounce gold price assumption. Our 2008 reserves would decline by
approximately 10% (8.2 million ounces), if calculated at a $675 per
ounce gold price. An increase in the gold price to $775 per ounce would
increase reserves by approximately 4% (3.3 million ounces), all other
assumptions remaining constant. For 2007, reserves were calculated at
a $575, A$750 or NZ$850 per ounce gold price assumption.
Edited extract from Newmont Mining, 2008 Annual Report,
Management Discussion and Analysis, page 27
5.67
Sensitivity analyses are rarely disclosed by other minerals or oil and gas
entities. Gold mining entities appear to be the exception because of the
extent to which the gold price is affected by speculation. The disclosure
of reserves sensitivities therefore helps the entity to show its exposure to
the gold price.
Reconciliation of changes in quantities from year to year
5.68
A disclosure that explains the changes in the entity’s reserves between
the current year and the preceding year should help users to obtain a
better understanding of the nature and extent of estimation
uncertainties associated with the reserves estimates. These uncertainties
may relate to geological, economic, legal and environmental conditions
as well as to governmental and sovereign risk factors. This type of
disclosure should also assist users in evaluating the entity’s financial
performance for the current reporting period by identifying, and
attributing quantities to, the significant causes for the change in the
entity’s reserves estimates—which would include production for the
current period and new additions to reserves arising from subsequent
discoveries.
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5.69
This explanation could be presented as a numerical reconciliation or as a
narrative discussion of the main reasons for change with the quantities
attributable to the change(s) being identified as part of the disclosure.
Current practice across the minerals and oil and gas industries is mixed
regarding whether an explanation is provided, and if it is, whether the
explanation is a numerical reconciliation or a narrative discussion. In the
project team’s opinion, the explanation format that provides the most
useful information will often depend on the level of disaggregation
associated with the reserve quantity disclosure. Disclosure of reserve
quantities at the property level (ie the mine or field) would make a
narrative discussion useful because the explanation could provide
specific comments on the cause(s) for the change, as well as quantifying
the quantities attributable to the change in estimate. However, if reserve
quantities are not disclosed for individual properties, a narrative
discussion of the reasons for change may be too complex to understand,
or too cumbersome to prepare, in which case numerical reconciliation
may be more suitable.
5.70
If a numerical reconciliation for a reserve quantity disclosure is provided,
the project team thinks that the reconciliation should identify changes
resulting from:
(a)
discoveries and extensions;
(b)
revisions of previous estimates, which may include revisions as a
result of:
(i)
geological factors (eg a better understanding of the geology as
a result of additional drilling activities);
(ii)
commodity price factors; or
(iii)
other economic factors (eg a change in taxation or discount
rates);
(c)
production of minerals or oil and gas;
(d)
acquisition of reserves through the purchase of minerals or oil and
gas properties; and
(e)
disposal of reserves through the sale or disposal of minerals or oil
and gas properties.
An example of a numerical reconciliation is provided at exhibit 5.2 above.
In addition, the project team recommends that a numerical
reconciliation should be complemented by a narrative discussion of the
reasons for significant changes in the estimate (if any), with the
discussion referring to the specific properties involved.
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5.71
If a narrative discussion is provided instead of a numerical reconciliation,
the project team expects that the discussion should provide users with at
least as much information on the reasons for change as would be
available in a numerical reconciliation. For this reason, the narrative
explanation of changes in the reserves estimate should include, at a
minimum, a discussion of all changes identified in the numerical
reconciliation. An example of a narrative discussion is provided at
exhibit 5.6 below, although it should be noted that this disclosure does
not quantify the gas production for the reporting period.
Exhibit 5.6
North West Shelf
Dry Gas
Proved
Proved +
Probable
Bcf
3,389
3,775
Condensate
MMbbl
70.6
101.9
Oil
MMbbl
11.2
19.6
New Reserves bookings were made for the Lady Nora discovery
(40 Bcf Dry Gas and 1.2 MMbbl Condensate Proved and 72 Bcf Dry Gas
and 2.3 MMbbl Condensate Proved plus Probable Reserves). In addition,
under the new 2007 SPE PRMS* guidelines an incremental 406 Bcf Dry
Gas Proved was booked, which takes into account the independence of
the individual North West Shelf field reservoir characteristics.
In addition to production, negative revisions of 2.6 MMbbl Proved and
13.4 MMbbl Proved plus Probable Oil Reserves were the result of
multi-disciplinary studies on Cossack Wanaea Lambert and Hermes and
the transfer of Egret Reserves to Contingent Resources (5.1 MMbbl).
Note: These volumes do not include the agreement to purchase reserves
from Shell, which was signed on 8 February 2008.
Edited extract from Woodside Petroleum, 2007 annual report, page 35
Disclosure type 2: Value-based information
5.72
Reserve quantity disclosure is useful for indicating the amount of
minerals or oil and gas that is expected to be economically recoverable,
but it does not provide any indication of the amount of future cash
inflows that those reserves might generate. Measuring minerals or oil
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and gas properties at fair value or some other form of current value could
provide this information, although as noted in Chapter 4 users expressed
limited interest in these assets being valued at fair value or some other
current value in the financial statements.
5.73
The types of value-based information about minerals or oil and gas
reserves that should be disclosed depends on the basis chosen for
measuring minerals or oil and gas properties in the statement of
financial position—either at historical cost or at fair value.
5.74
If these assets are to be measured at historical cost (which is the project
team’s recommendation in Chapter 4), the project team recommends
that information relating to a current value measurement of these assets
should be disclosed. The features of this proposed disclosure are
discussed in Disclosure type 2A below.
5.75
Alternatively, if the decision is to measure these assets at fair value
(which the project team has not recommended), the disclosure that
should be provided is disclosure that amplifies the fair value that is
presented in the financial statements. The features of this proposed
disclosure are outlined in Disclosure type 2B below.
Disclosure type 2A: Current value measurement
5.76
The main current value measurement options under consideration for
disclosure are:
(a)
Alternative A—a valuation of an entity’s minerals or oil and gas
properties that is based on fair value measurement principles but
presented as a valuation range rather than as a single point
estimate; or
(b)
Alternative B—a measure of the discounted cash flows attributable
to an entity’s reserves.
Alternative A—valuation range estimates based on fair value
measurement principles
5.77
Disclosing a range of fair value estimates for minerals or oil and gas
properties has many of the conceptual benefits of fair value
measurement without requiring management to present its fair value
estimate as a single point estimate. Consequently, this disclosure could
overcome some of the concerns raised about the potential variability
associated with measuring minerals or oil and gas properties at fair value.
The variability arises because the valuation requires many assumptions
to be made, and many of those assumptions are based on unobservable
inputs. The variability of the estimate can be further pronounced because
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the assets often have long useful lives and may contain ‘option value’
relating to future development or exploration potential. As a result, the
fair value measurement of these assets can be susceptible to material
changes in value resulting from only small changes in the assumptions
used. The project team notes that disclosing the valuation as a range
might help to address this by recognising the uncertainty associated with
these assumptions. A similar disclosure approach was adopted in IAS 40
and IAS 41, which require the disclosure (if possible) of a range of
estimates within which fair value is highly likely to lie for those
investment properties and biological assets where fair value cannot be
measured reliably.*
5.78
The usefulness of this disclosure would depend on whether the valuation
range is sufficiently narrow to allow users to relate the range of estimates
of fair value to the assumptions used. Other information that would also
need to be disclosed includes the main assumptions used to prepare the
estimates, the sensitivity of the ranges to changes in the main
assumptions and a reconciliation of the changes in the valuation range
between reporting periods. This information would also be necessary if a
single point estimate of fair value was provided (see paragraph 5.96
below). The main difference in the disclosure is likely to be that because
of difficulties with presenting a quantitative reconciliation of changes in
a valuation range, a narrative discussion of the main reasons for change
may need to be disclosed as a substitute for a quantitative reconciliation.
5.79
The project team acknowledges that many of the concerns raised by users
and preparers with the fair value measurement of minerals or oil and gas
properties (as discussed in Chapter 4) apply equally to the disclosure of a
range of fair value estimates. For instance, many of the concerns
expressed by preparers about the cost and effort associated with
preparing fair value estimates would remain. This also includes the
concern expressed by users that they would not directly use the fair
values in their own analysis because the estimates may be based on inputs
that are different from those that they would apply. Therefore, although
the disclosure of a valuation range may provide some useful information
about the variability of the estimate, the project team thinks that the
benefit of disclosing a range of fair value estimates for minerals or oil and
gas properties would not exceed the costs of preparing those estimates.
*
IAS 40 paragraph 79(e)(iii) and IAS 41 paragraph 54(c)
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Alternative B—discounted cash flow measurement of proved
and probable reserves
5.80
The project team proposes that the current value measurement
disclosure should be a discounted cash flow measurement of an entity’s
reserves. This disclosure is similar to the disclosure of a standardised
measure of proved oil and gas reserves that is required by FASB ASC
paragraph 932-235-50-30. As such, it is not an estimate of the fair value of
the entity’s minerals or oil and gas properties.
5.81
The project team concluded in Chapter 4 that this type of current value
measurement is not suitable as a measurement basis for minerals or oil
and gas properties in the statement of financial position. However, the
project team thinks that this type of current value measurement should
be disclosed nevertheless, because users familiar with the disclosure of
the standardised measure indicated that it can provide useful
information. Significantly, these users indicated that the disclosure of
the standardised measure is useful even though, as noted in Chapter 4,
the valuation itself is not. This may seem paradoxical; however, it is a
reflection on how the information is used—and on what information is
used. This is discussed further in paragraphs 5.85 and 5.88.
Categories of reserves to be valued
5.82
The project team proposes that the current value measurement that is
disclosed should measure the entity’s proved and probable reserves.
As noted above, proved and probable reserves represent the best estimate
of the entity’s economically recoverable reserves on the basis of current
approved development plans. Therefore, the valuation of these categories
represents in effect a best estimate valuation, but without consideration
of any future development or exploration potential that may exist at
those properties. This would reduce, to some extent, the variability
associated with the estimate. It would also reduce the time and cost
associated with preparing the estimate.
5.83
A valuation based on proved and probable reserves is also consistent with
the reserve quantities disclosure requirement, thereby providing a
linkage between the reserve quantities and the future cash flows that
could be generated from those quantities assuming the standardised
conditions were to apply. The standardised measure disclosure required
by FASB ASC paragraph 932-235-50-30 is limited to proved reserves.
Therefore, even if this level of disclosure was considered sufficient for
users in the oil and gas industry, it would not be suitable for application
in the minerals industry because there are some minerals deposits that
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can only satisfy the probable reserves classification. Omitting probable
reserves from the standardised measure would therefore not provide for
comparable levels of information being made available to users in the
two industries.
Preparation basis
5.84
The current value would be measured using discounted cash flow
techniques. Although the current value estimate could be prepared using
market participant assumptions (where available), users surveyed by the
project team indicated that if a current value estimate is provided, the
assumptions underpinning the estimate should be standardised. This
would lessen the extent to which the measurement is based on subjective
forecasts of future conditions. Differing views were expressed on how to
determine the standardised parameters for the economic assumptions,
but the general thrust of the comments was:
(a)
for commodity prices—use a standardised price assumption such as
historical average price or a current market price.
(b)
for development and operating costs—use current costs.
(c)
for discount rates—use a standardised discount rate or the entity’s
weighted average cost of capital (which would be disclosed).
Components of the current value measurement disclosure
5.85
Under FASB ASC paragraph 932-235-50-31, the components of the
standardised measure are separately disclosed (eg future cash inflows,
future production costs, future development costs, future income taxes
and the effect of the discount rate). One of the uses of the disclosure of
the individual components of the standardised measure is to compare the
undiscounted future cash inflows from production with the discounted
cash flow measurement to obtain some understanding of when the entity
is expecting to produce the reserve quantities.
5.86
The project team recommends adopting a similar disclosure approach.
Consequently, the current value measurement should be disclosed in
conjunction with:
(a)
an explanation of the main assumptions made, including
standardised assumptions; and
(b)
a breakdown of the main components of the measurement. At a
minimum, this would be expected to include:
(i)
future production revenues;
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5.87
(ii)
future operating and development expenditures (to be
presented separately if feasible);
(iii)
future royalty and taxation expenditures; and
(iv)
the effect of discounting.
An example of the standardised measure required by FASB ASC paragraph
932-235-50-30 is provided below at exhibit 5.7.
Exhibit 5.7
(€ million)
Italy
North
Africa
West
Africa
North Caspian Rest of
Total
Total joint
Sea
Area World consolidated ventures and
subsidiaries
associates
At December 31,
2008
Future cash
inflows
46,458
Future
production
costs
62,785 22,344
16,056 22,199 13,622
183,464
4,782
(5,019) (10,673) (6,715)
(3,414) (6,380) (2,715)
(34,916)
(1,104)
Future
development
and
abandonment
costs
(6,805)
(6,153) (3,868)
(2,166) (5,114) (1,897)
(26,003)
(1,845)
Future cash
inflow before
income tax
34,634
45,959 11,761
10,476 10,705
122,545
1,833
Future
income tax
(11,329) (27,800) (5,599)
(7,621) (2,781) (1,901)
(57,031)
(1,032)
Future net
cash flows
23,305
2,855
65,514
801
(34,062)
(763)
31,452
38
18,159
6,162
10% discount (13,884)
factor
(8,639) (2,155)
Standardized
measure of
discounted
future net
cash flows
9,520
9,421
4,007
7,924
9,010
7,109
(869) (6,272) (2,243)
1,986
1,652
4,866
Edited extracts from Eni Annual Report 2008, page 255
Reconciliation of current value measurement
5.88
Users indicated that they are interested in how the standardised measure
changes over time. FASB ASC paragraph 932-235-50-35 requires a factor
analysis of the year-on-year changes to the standardised measure,
showing the impact of changes in prices, costs, reserve discoveries etc.
This provides users with information on the sensitivity of the value of
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reserves to changes in these factors. Although the assumptions behind
the standardised measure may not be relevant, the effect of changes in
those assumptions is considered useful information.
5.89
5.90
For that reason, if a current value measurement is disclosed, the project
team recommends that an explanation of the changes in the current
value measurement between the current year and the preceding year
should also be provided. The reconciliation should identify the
significant causes for the change in the measurement. This should
include separately identifying the future cash flow impact of the changes
identified in the reserve quantity reconciliation (see paragraph 5.70
above) as well as the future cash flow impact of other measurement
assumptions, such as changes in:
(a)
commodity prices;
(b)
operating costs;
(c)
development costs;
(d)
taxation and royalty arrangements; and
(e)
the discount rate and the accretion of the discount.
An example of the reconciliation of the standardised measure required by
FASB ASC paragraph 932-235-50-35 is provided at exhibit 5.8 below.
Exhibit 5.8
Changes in standardized measure of discounted future net cash flows
(€ million)
2008
Beginning of year
53,893
Beginning of year related to joint venture and associates
(891)
Beginning of year consolidated
53,002
Increase (decrease):
•
sales, net of production costs
(26,202)
•
net changes in sales and transfer prices, net of production costs
(39,699)
•
extensions, discoveries and improved recovery, net of future
production and development costs
•
changes in estimated future development and abandonment
costs
•
development costs incurred during the period that reduced
future development costs
1,110
(6,222)
6,584
continued...
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...continued
•
revisions of quantity estimates
5,835
•
accretion of discount
10,538
•
net change in income taxes
21,359
•
purchase of reserves in-place
•
sale of reserves in-place
•
changes in production rates (timing) and other
476
25
4,646
Net increase (decrease)
(21,550)
Standardized measure of discounted future net cash flows
consolidates
31,452
Standardized measure of discounted future net cash flows joint
ventures and associates
Standardized measure of discounted future net cash flows
38
31,490
Edited extracts from Eni Annual Report 2008, page 256
Disaggregation basis for a current value measurement and
reconciliation
5.91
Ideally, the current value measurement would be provided for each
geographical location to complement the information provided in the
reserve quantity disclosures.
Disaggregating these disclosures by
commodity type as well may not always be feasible because many
minerals or oil and gas properties include more than one commodity
(eg copper and gold, or oil and natural gas). In these cases, providing
separate value-based disclosures for each commodity would require the
future development and operating costs to be arbitrarily allocated to the
current value measurement of each commodity. This could lessen the
usefulness of a commodity-specific current value measurement.
5.92
The project team also acknowledges that disclosing a current value
measurement and a reconciliation of that measurement on the same
geographical basis as the reserves disclosure could cause preparation and
presentation difficulties, especially for large diversified minerals and oil
and gas entities. This is because of the volume of information that would
need to be disclosed. A higher level aggregation may therefore need to be
considered.
The project team proposes that the current value
measurement disclosure and the reconciliation disclosure should be
presented by major geographical region because users surveyed by the
project team generally indicated that disclosing this information at this
level of aggregation would be sufficient for their needs.
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5.93
Another approach is to present the current value measurement
reconciliation at a higher level of aggregation than the reserve quantity
and current value measurement disclosures. The FASB made a similar
decision for the reconciliation of the standardised measure after
considering the cost-benefit implications of requiring the disclosure of a
disaggregated value-based reconciliation. Further consideration should
be given to which of these approaches is preferable on cost-benefit
grounds.
Cost-benefit considerations
5.94
Preparers in the minerals and oil and gas industry do not support a
requirement to disclose a current value measurement of minerals or oil
and gas properties. They do not believe that the disclosure can be
justified on cost-benefit grounds, owing to the expected costs involved to
prepare the disclosure and the limited benefits they believe it would
provide to users (especially users who are not familiar with the disclosure)
given that the measurement does not provide a meaningful assessment
of value. They also believe that the current value measurement has no
relevance for internal management purposes.
Disclosure type 2B: Fair value measurement – disclosures
that amplify the fair value measurement of minerals or oil
and gas properties
5.95
If the statement of financial position measurement basis for minerals or
oil and gas properties is fair value, the project team considers that
disclosures similar to the fair value disclosure proposals in paragraph 57
of the exposure draft Fair Value Measurement and the disclosures required
by paragraphs 47 and 50 of IAS 41 may be relevant. The purpose of these
disclosures would be to provide users with information to assess the
inputs used to develop the fair value measurement of the minerals or oil
and gas properties and the effect that the asset measurement has on the
statement of comprehensive income for the reporting period.
5.96
The types of information that should be disclosed to amplify the fair value
measurement of minerals or oil and gas properties would include:
(a)
the fair value measurements at the reporting date.
(b)
the level within the fair value hierarchy in which the fair value
measurements in their entirety fall. As noted in Chapter 4, the fair
value of minerals or oil and gas properties are expected to be based
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on significant unobservable inputs, and therefore the fair value
measurements will generally be regarded as Level 3 fair values.
5.97
(c)
the disclosure of the main assumptions used in the fair value
measurement estimate, including assumptions for commodity
prices and discount rates.
(d)
a reconciliation from the beginning balances to the ending
balances of the fair value measurements, disclosing separately
changes during the period attributable to the following:
(i)
discoveries and extensions;
(ii)
revisions of previous estimates owing to geological factors;
(iii)
commodity price factors or other economic factors;
(iv)
production of minerals or oil and gas;
(v)
purchases of minerals or oil and gas properties; and
(vi)
sales of minerals or oil and gas properties.
(e)
if changing one or more of the inputs to reasonably possible
alternative assumptions would change fair value significantly, the
entity should state that fact and disclose the effect of those
changes. The entity should disclose how the effect of a change to a
reasonably possible alternative assumption was calculated. For this
purpose, significance should be judged with respect to profit or
loss, and total assets or total liabilities, or, when changes in fair
value are recognised in other comprehensive income, on total
equity.
(f)
the valuation technique(s) used to measure fair value and a
discussion of changes in valuation techniques, if any, during the
period.
The project team proposes that for these fair value disclosures relating to
minerals or oil and gas properties to be useful, the level of disaggregation
should be consistent with the disaggregation approaches identified for
Disclosure type 2A.
Disclosure type 3: Production revenues
5.98
The disclosure of an annual reconciliation of changes in reserve
quantities estimates will show production quantities. However, users are
also interested in knowing the revenue that is earned from that
production, either by sales to third parties or from inter-entity transfers
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of the produced commodity to the entity’s downstream operations.
The separate disclosure of this information may assist users to value an
entity’s upstream and downstream operations separately.
5.99
Production revenue information is typically disclosed in accordance with
the requirement in paragraph 35(b) of IAS 18 Revenue to disclose the
amount of each significant category of revenue recognised during the
period. Furthermore, production revenue by commodity is sometimes
disclosed in segment reporting disclosures or in other information that is
made publicly available by entities in the extractive industries.
The project team recommends that the disclosure of production revenues
should generally need to be presented separately only by commodity.
This is because most of the commodity prices are set by international
markets rather than by domestic considerations. Disclosing revenue by
commodity would also complement the disclosure of production
quantities, and thereby enable users to determine the average price
realised on the sale of the entity’s production. Separate presentation of
production revenue by geography is recommended only if the commodity
price is subject to local market conditions, for instance the sale of gas into
domestic markets or gravel and aggregates in the minerals industry.
Disclosure type 4: Time series of exploration, development
and production cash outflows
5.100
Disclosing the exploration, development and production cash outflows
that were made in the current and prior periods would provide
information that can be used to assess the entity’s performance.
For instance, the disclosure of this cash flow information should help
users to calculate measures such as cash costs per unit of product (eg cash
cost per ounce of gold) or to perform finding and development cost
analysis in the oil and gas industry.
5.101
Because it would not be feasible to provide this cash flow information on a
cumulative basis, the project team proposes that the disclosure of
exploration, development and production cash outflows should be
provided as a time series over a period that is sufficient to enable the
identification of trends (possibly over five years). This information should
be provided at the same level of disaggregation as the reserves quantity
disclosure. An example of this type of disclosure is presented at exhibit 5.9
below, noting that it does not include the disclosure of production costs.
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Exhibit 5.9
Exploration and Development Costs
Year ended December 31
Millions of dollars
2006
2008
2007
2005
2004
United States
California
Exploration
$
Development
–
4 $
$
928
1,198
–
$
686
–
$
494
–
412
Gulf of Mexico
Exploration
Development
682
617
705
612
478
1,923
2,237
1,632
639
475
46
37
46
32
5
1,497
1,775
868
596
372
Other U.S.
Exploration
Development
Total United States
Exploration
$
Development
728 $
4,348
658
$
5,210
751
$
3,186
644
$
1,729
483
1,241
International
Africa
Exploration
Development
$
347 $
3,723
408
4,176
$
379
$
2,890
225
$
1,871
271
1,047
Asia-Pacific
Exploration
Development
516
324
314
124
82
4,484
1,897
1,788
1,026
567
Indonesia
Exploration
Development
68
64
90
31
15
753
620
460
325
245
270
372
388
341
226
1,879
1,504
1,019
713
542
$ 1,201
$ 1,168
$ 1,171
10,839
8,197
6,157
Other International
Exploration
Development
Total International
Exploration
Development
$
721
3,935
$
594
2,401
Edited extracts from Chevron Corporation 2008 Supplement to the Annual
Report, page 41
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Chapter 6 – Publish What You Pay proposals
Introduction
6.1
A coalition of non-governmental organisations is promoting a campaign
called Publish What You Pay (PWYP), which aims to help citizens of
resource-rich* developing countries hold their governments accountable
for the management of revenues from the minerals and oil and gas
industries. This requires reliable information about the revenues
received by a government from these industries. To achieve this, PWYP
proposes that entities undertaking extractive activities should be
required to disclose, in their financial reports, the payments they make
to each host government. These payments could be in cash or in kind and
should be disclosed on a country-by-country basis.
6.2
PWYP also proposes that disclosures should be provided on a country-bycountry basis for other types of information including minerals or oil and
gas reserve quantities, production quantities, production revenues, and
costs incurred in development and production. The objective of these
disclosures is to provide information on the scale of the entity’s
operations within individual countries. Citizens of resource-rich
developing countries can compare this information with the amounts an
entity has paid to governments of those countries.
6.3
This chapter analyses the PWYP proposals from two perspectives:
(a)
whether, and to what extent, the disclosures are consistent with
the objectives of general purpose financial reporting; and
(b)
whether the disclosures can be justified on cost-benefit grounds.
Background
6.4
The project team’s analysis of these proposals takes into account the
input provided by a round-table discussion on the PWYP disclosure
proposals that was held in London on 15 September 2008. The round
table was jointly sponsored by the Revenue Watch Institute† and the IASB.
*
The IMF Guide on Resource Revenue Transparency (2007) states that a ‘country is considered
rich in hydrocarbons and/or mineral resources if it meets either of the following
criteria: (i) an average share of hydrocarbon and/or mineral fiscal revenues in total fiscal
revenue of at least 25 percent during the period 2000-2005 or (ii) an average share of
hydrocarbon and/or mineral export proceeds in total export proceeds of at least
25 percent during the period 2000-2005’.
†
The Revenue Watch Institute is a member of the PWYP coalition.
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Participants included investors, preparers and auditors involved in the
minerals and oil and gas industries, as well as representatives from PWYP,
members of the project team, four members of the IASB and a
representative of the International Public Sector Accounting Standards
Board. Responses from the user survey and from further discussions with
some investors are also considered in the following analysis.
PWYP proposals
6.5
The disclosures proposed by PWYP are presented at Figure 6.1 below.
Figure 6.1 – PWYP disclosure proposals
1. Benefit streams to government:
The significant components of the total benefit streams to government
and its agencies should be disclosed on a country-by-country basis. At a
minimum, this would include separate disclosure of:
•
royalties and taxes paid in cash
•
royalties and taxes paid in kind (measured in cash equivalents)
•
dividends
•
bonuses
•
licence and concession fees.
2. Reserves:
Reserves volumes and valuation measures (if required by the future
IFRS) should be disclosed on a country-by-country basis.
3. Production volumes:
Production volumes for the current reporting period should be
disclosed on a country-by-country basis. Optional disclosure of
production volumes by key products and key properties is encouraged.
4. Production revenues:
Revenues from production should be disclosed on a country-by-country
basis, with separate disclosure of production revenue attributable to:
•
sales to external customers
•
transfers to downstream operations
continued...
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...continued
5. Costs:
The following costs should be disclosed on a country-by-country basis:
• production costs
• development costs.
6. Key subsidiaries and properties:
The names and locations of each key subsidiary and property in each
country should be disclosed.
6.6
The PWYP proposals are intended to complement the Extractive
Industries Transparency Initiative (EITI), which encourages governments
of resource-rich developing countries to ‘publish what you earn’.* Both
initiatives have the objective of promoting a more accountable system for
the management of natural resource revenues, which in turn should help
to combat corruption, improve governance and promote sustainable
development in these countries. The EITI and other aspects of the PWYP
campaign are outside the scope of this discussion paper.†
Disclosure in financial reports
6.7
PWYP recommends that its disclosure proposals should be incorporated
into an eventual IFRS for extractive activities. They regard IFRSs as
offering the best mechanism for creating a global and enforceable
standard that will generate comparable information. Some entities in
the minerals or oil and gas industries disclose some of the types of
information being proposed by PWYP, but those disclosures are mainly
*
The EITI is an international initiative in which producing countries voluntarily agree to
follow established processes to improve the transparency of the payments made by
companies, receipts by government and the reconciliation of the two sets of figures. Once
a country has signed, the rules state that all companies operating in the territory should
disclose their payments to government. Although 30 countries are members of EITI, not
all have reached the stage of publishing their reports. Some publish only aggregated
company data, while other EITI countries publish company-by-company data. A large
number of companies, NGOs, investors, industry associations and intergovernmental
organisations such as the World Bank and IMF are supporting the EITI.
†
More information on the PWYP campaign and the EITI is available from
http://www.publishwhatyoupay.org/ and http://www.eitransparency.org/.
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found in corporate social responsibility reports or sustainability reports
published by the entity. PWYP’s primary concerns with the information
being reported in this manner are that it is:
(a)
voluntary—which makes it difficult to estimate reasonably how
much natural resources income a host government is receiving if
most entities that operate in the country are not disclosing the
relevant payments;
(b)
not standardised—which makes it difficult to compare and compile
the information provided by different entities;
(c)
not audited or traceable back to the financial statements—which
means that the information reported is perceived to lack the
reliability and credibility associated with financial reports.
These concerns would be overcome if an IFRS were to require the
disclosures.
Relationship between the PWYP proposals and the
objectives of financial reporting
6.8
Before addressing whether any of the proposals should be included in an
IFRS, the extent to which the PWYP disclosure proposals might be
consistent with the objectives of general purpose financial reporting
needs to be considered. This involves considering whether:
(a)
users of the PWYP proposals are also primary users of financial
reports; and
(b)
the PWYP proposals are within the scope of financial reports.
Users of the PWYP proposals
6.9
6.10
The information provided by the PWYP proposals would be mainly used by:
(a)
citizens
of
resource-rich
developing
countries
and
non-governmental organisations, primarily to hold the
governments of those countries accountable for the management
of natural resource revenues; and
(b)
capital providers, to the extent that the information is useful for
assessing an entity’s exposure to country risk and reputational risk.
Although each of these users of the PWYP proposals can be users of
general purpose financial reports, the Framework indicates that financial
reporting is primarily directed to meet the needs of existing and potential
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equity investors, lenders and other creditors (ie capital providers).*
Information that is useful to capital providers for making decisions may
also be useful to other users of financial reporting. These other users
include suppliers, customers and employees (when not acting as capital
providers), as well as governments and their agencies and members of the
public. However, financial reporting is not directed to meeting the
specialised needs of those other users. For this reason, the PWYP
proposals have been assessed only from the perspective of whether capital
providers would find the information useful.
In this context,
information may be regarded as useful if it is used to assess the future
cash flows, including the riskiness of those cash flows (noting that this is
also consistent with the disclosure objective identified in paragraph 5.5).
Scope of financial reports
6.11
6.12
In Chapter 1 the project team proposed that, for the purposes of this
discussion paper, financial reporting should be regarded as including
information that:
(a)
helps users of financial reports to make decisions;
(b)
can reasonably be viewed as being within the scope of a complete
set of financial statements; and
(c)
meets a cost-benefit test.
IAS 1 Presentation of Financial Statements provides some examples of types of
reporting that are outside the scope of IFRSs, and arguably outside the
scope of financial statements altogether. Paragraph 14 states that
Many entities also present, outside the financial statements, reports and
statements such as environmental reports and value added statements,
particularly in industries in which environmental factors are significant and
when employees are regarded as an important user group. Reports and
statements presented outside financial statements are outside the scope of
IFRSs.
However, even though corporate social responsibility reports and
sustainability reports are outside the scope of IFRSs and may contain
similar information to that being proposed by PWYP, this does not
necessarily mean that the PWYP proposals are outside the scope of
financial reporting. Rather, the project team considers that the
disclosures could be reasonably viewed as being within the scope of
financial reporting if capital providers—as the primary users of financial
reports—consider that the information is important for making informed
*
See paragraphs OB2 and OB6–OB9 of the Framework.
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investment and lending decisions and to the extent that similar
information cannot be readily obtained from other sources. The project
team also notes that the type of information in the disclosures proposed
by PWYP is either revenue and cost information that is inherently part of
financial statements or is information related to reserve quantities that
is similar to disclosures proposed in Chapter 5 of this discussion paper.
A crucial question is the level of detail in the PWYP proposals—the
requirement for disclosure on a country-by-country basis. This leads to
the importance of considering the cost-benefit implications of providing
this information within a financial report.
Usefulness of the PWYP proposals to capital providers
6.13
Users told the project team that country-level information helps in
assessing the risks that an entity is exposed to from operating in those
countries. The PWYP proposals are expected to be useful to capital
providers to the extent that they provide information that can be used to
make judgements about the entity’s exposure to:
(a)
country-specific investment risks; and
(b)
reputational risk.
Relevance of the scale of an entity’s operations in individual
countries for assessing country-specific investment risks
6.14
Most of the PWYP proposals provide information about the scale of an
entity’s operations within individual countries. This information could
be used to assess the effect that country-specific investment risks may
have on an entity. Country-specific investment risks may include:
(a)
economic risks relating to changes in foreign exchange rates and
cost inflation;
(b)
political and social risks relating to changes in government,
expropriation of assets and civil unrest; and
(c)
legal and regulatory risks relating to changes in the taxation or
royalty regimes and rates and changes to other legal rights and
obligations that may affect the entity.
Although these types of risks are not unique to the extractive industries
or to resource-rich developing countries, they are generally viewed as
being more prevalent and more pronounced in these industries and
countries.
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6.15
The effect that country-specific investment risks may have on an entity
depends on the materiality (in quantitative terms)* of its investments in
that country relative to its overall financial position and performance. This
is because the potential economic loss (or gain) to the entity arising from
country-specific investment risks would be expected to be correlated to the
relative value of the entity’s investments in that country.
6.16
The PWYP proposals that may be useful for identifying the materiality of
an entity’s investments in specific countries, and the contribution those
investments have on the entity’s financial performance, include the
country-by-country disclosure of:
6.17
(a)
reserve quantities—to provide an indication of the value of the
entity’s minerals or oil and gas properties in the country;
(b)
production quantities and revenues—to
performance of those properties; and
(c)
development and production costs—to quantify the capital that the
entity is investing in the country and to assess the profitability of
its operations.
show
the
current
The usefulness of this information was confirmed by users surveyed by
the project team. As discussed in more detail in Chapter 5, these users
generally indicated that information about reserve quantities,
production and costs is relevant to their investment decision-making and
should, at a minimum, be disclosed at the country level if the operations
in that country are material to the entity.† In contrast, other users such as
citizens and non-governmental organisations are seeking the disclosure
of this information for each country regardless of whether the operations
and investments in the country are material in amount to the entity. This
represents a difference in needs between capital providers and citizens
and non-governmental organisations.
Relevance of payment to governments for assessing
country-specific investment risks and reputational risks
6.18
The disclosure of payments made by the entity to governments in their
dual capacity as a taxation authority and as the owner of the minerals or
*
Materiality depends on the amount of the item (a quantitative factor) and the nature of
the item (a qualitative factor). Information is considered to be material if its omission
or misstatement could influence the decisions that users make on the basis of an
entity’s financial information.
†
Chapter 5 explains that some users, particularly mining analysts, suggested that some
reserve volumes and production disclosures should be more specific—for example,
presented separately for each major mine.
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oil and gas is the centrepiece of the PWYP proposals. PWYP’s intention is
for these disclosures to be presented on a cash basis rather than an
accruals basis, with payments in kind included at a cash-equivalent
amount. Cash basis disclosure is preferred by PWYP because it would
provide visibility of the amounts that are paid to governments. Separate
disclosure of the major types of payments to governments is proposed
because some payments, particularly non-recurring payments such as
signature bonuses, are regarded as being more susceptible to misuse.
6.19
Consultations with investors on the PWYP proposals indicated that the
disclosure of payments to governments would be useful in making
investment decisions. This information could be useful in assessing the
likelihood of a country-specific investment risk occurring and the entity’s
exposure to reputational risk. Investment risk assessments may take into
account the size and the timing of the payments being made to
governments.
For instance, an economic risk assessment of an
investment is likely to be different if a substantial signature bonus is paid
in advance of knowing whether development and production on the
property will be successful, compared with paying royalties levied on
production and which should therefore be capable of being paid out of
operating cash flows. In addition, some investors indicated that they
would also use this information in assessing whether the investment
satisfies their socially responsible investment criteria. To be useful for all
these purposes, the disclosure of payments to governments would need to
be presented on a country-by-country basis. Presenting these disclosures
at a regional level, whereby the payments to the governments of
individual countries within that region are aggregated, is not useful for
these purposes.
Assessing the likely occurrence of country-specific investment risks
6.20
Some investors indicated that a key component of their country-specific
investment risk assessments for individual entities relates to judgements
about the existence and extent of corruption within the resource-rich
countries in which entities operate. The disclosure of payments to
governments can be used to provide a preliminary indication of possible
corruption levels that may be present within a government, because it
would enable users to compare the payments made to governments by
entities in the extractive industries with the revenue that governments
report they have received from those taxes, royalties and other revenue
flows. Generally speaking, the greater the level of corruption, the greater
the investor’s concern about the integrity of the government and its
commitment to honour existing terms and conditions relating to an
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entity’s operations in that country. For instance, a government may
make unilateral modifications to the entity’s legal rights to explore and
extract minerals or oil and gas, the entity’s interests in joint
arrangements, and the taxation or royalty arrangements that apply to the
entity. These modifications could have significant effects on the value
attributable to an entity’s operations in that country. Consequently,
investors would place a higher risk premium on their investments in
entities that have operations in those countries or alternatively they
might choose to avoid investing in those entities.
6.21
Investors also acknowledged that the disclosure of payments to
governments should have wider social benefits for resource-rich
developing countries by helping to improve the governance structures, and
therefore the political, economic and social stability of those countries.
Separate disclosure by type of payment could also improve governance
structures and stability within countries where regional or local
governments are receiving revenue directly from minerals or oil and gas
entities or through revenue-sharing mechanisms with the national
government. This is because, as noted by PWYP, typically only certain types
of revenue streams flow to the regional or local government, and so those
revenues are more likely to be identifiable if there is separate disclosure by
type of payment. Improvements to governance structures and stability
should have a positive influence on the well-being of the citizens of those
countries and, ultimately, these improvements should also result in a
lower risk premium being placed on investments in those countries.
Assessing reputational risk
6.22
An entity’s reputation may be harmed if it is perceived to be associated
with, or complicit in, corrupt government practices that have adverse
social or environmental consequences. It may also be harmed if the
entity is not perceived to be ‘paying its fair share’ in exchange for
extracting a country’s natural resources. This is one of the reasons for
entities voluntarily publishing corporate social and sustainability
reports. In this context, PricewaterhouseCoopers has put forward a
model for calculating an entity’s total tax contributions.*
6.23
Reputational risks can have economic consequences and capital
providers would be expected to consider this when making their
investment decisions. Direct costs associated with a loss of reputation
might include compensation or remediation works to make good for the
consequences of the entity’s actions (real or perceived). Indirect costs
*
This model is explained in Total Tax Contribution Framework: What is your company’s overall
tax contribution?, published by PricewaterhouseCoopers.
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might include difficulties in ‘winning’ further business, such as securing
new exploration and extraction rights or participation in joint
arrangements, or in obtaining additional equity or debt financing.
6.24
Unlike investment risks, an entity’s exposure to reputational risks and
the associated potential economic loss is not correlated to the scale of the
entity’s investment in a particular country. This is an important point,
particularly for large diversified minerals and oil and gas entities that
may have operations in countries that are immaterial in size to the entity.
Although immaterial to the entity in quantitative terms, the entity’s
operations in some of those countries could be material to the entity in
qualitative terms (eg material to the entity’s reputation) if, for example,
the country was economically dependent on the investments made by the
entity or if the political, social or environmental conditions in that
country could be reasonably viewed as exposing the entity to reputational
risks. It will not always be clear whether a country is material to the
entity in this way, but ultimately this decision rests with the entity. Some
participants at the round-table meeting suggested that the entity should
use its best efforts to disclose payments to governments whenever there
is a reasonable expectation that the entity’s operations would be material
to the country, even though the country might not be material to the
entity in quantitative terms.
Obtaining similar information from other sources
6.25
Respondents to the user survey and other investors whom the project
team consulted indicated they often assess country risks (including
corruption) and reputational risks using primarily qualitative
information from sources such as security risk consultants’ reports.
Some investors also refer to other relevant sources, which depending on
the country and the entity, may include EITI reports, non-governmental
organisations’ reports (eg Transparency International), and individual
corporate social and sustainability reports. Investors noted that, if
payments to governments were disclosed (on a comparable basis between
entities), they would use this information directly in making their
investment decisions. Security risk consultants and non-governmental
organisations would be expected to use this information to refine their
own assessments of individual country risks, noting that these
assessments may also be reviewed by investors when making their
investment decisions. This suggests that disclosures of payments to
governments would be used in assessing risks associated with investment
decisions, regardless of whether that information is used by the investor
directly or indirectly after considering a security risk assessment or
similar analysis.
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Cost-benefit implications of the PWYP proposals
6.26
The previous section showed that, on the whole, the PWYP proposals would
provide useful information to capital providers. This section considers the
cost-benefit implications associated with the disclosures being proposed by
PWYP, as identified in Figure 6.1 above. The cost-benefit analysis does not
contemplate the disclosure of information that is not material to the entity
from either a quantitative or qualitative perspective. To do so would be
inconsistent with paragraph 31 of IAS 1 Presentation of Financial Statements,
which states that an entity’s financial report does not need to provide a
specific disclosure required by an IFRS if the information is not material.
PWYP disclosure 1: Payments to governments
6.27
Figure 6.1 lists a variety of payments and other types of benefit streams
that governments may receive from entities in the extractive industries.
For the purposes of this discussion paper, the project team has not
assessed the detail of how to calculate the payments to governments and
which types of payments (or benefit streams) should be separately
disclosed. The purpose of the discussion paper is instead to seek views on
the general proposition that an entity engaged in extractive activities
should be required to disclose payments it makes to governments, either
separately or in total, because it provides useful information to capital
providers and that the benefits of this information exceed the cost of
providing it.
Additional benefit
6.28
Disclosing payments made to governments may provide users with
additional information on an entity’s taxation and royalty obligations.
Respondents to the user survey indicated that understanding an entity’s
taxation and royalty obligations is particularly important in the
extractive industries because of the generally higher tax or royalty rates
relative to other activities and, in many cases, the complexity of the
taxation or royalty regime. Most of the respondents indicated that
disclosing the effect of taxation and royalty obligations is an area where
financial reporting could make improvements. Users can typically model
the effect of tax and royalty obligations when information about the
features of the taxation or royalty regimes that apply in each country is
publicly available. However, users find it difficult to model these
obligations when the features of the regime are not known, which is
more likely to be the case for contractually imposed royalties such as
production sharing contracts (PSCs).
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6.29
The difficulty in accessing and comparing this information was identified
by users as another problem. For instance, it was noted that in
accounting for various oil and gas royalty obligations (including PSCs),
the effect is sometimes reflected in total in the reserve quantities
disclosure and sometimes in the statement of comprehensive income in
relation to the current period as part of production costs, operating
expenses or income taxes.
6.30
The project team expects that, if payments to governments were disclosed
in financial reports, this information could be used by users to help
validate their modelling of taxation and royalty regimes and to make
better comparisons across entities.
Preparation costs
6.31
*
There will be a cost associated with preparing and presenting this
information in a financial report. Some entities indicated that significant
changes to accounting systems and reporting processes would be required
to capture those data and to collate them on a country-by-country basis.*
It was noted that payments other than income tax amounts are not always
separately identified in the general ledgers of subsidiary entities. The types
of payments that might not be easily identifiable from a general ledger
include:
(a)
taxes or royalties paid in kind rather than cash;
(b)
indirect taxes and excise duties that are included in the cost of
goods or services purchased from third parties; and
(c)
net payments to governments that include both a tax or royalty
component (ie a non-reciprocal transfer) and a purchase or sale
transaction component (ie reciprocal transfer). These types of
payments could be even more difficult to identify if it is unclear
from the general ledger whether the recipient of the payment is a
government agency.
A similar observation is made in the PricewaterhouseCoopers publication Total Tax
Contribution: Global study for the mining sector, 2009, which states that ‘For most of the
participating companies, this was the first time such data has been put together to
show a picture of their real tax footprint. Each company carried out a data collection
exercise to extract the relevant data from their books and records. It should be
emphasised that not all of the participants were able to provide all of the data
requested. In addition, each participant covered only some, not all, of their countries of
operation.’ The publication also concluded that ‘… In PwC’s view, every mining
company needs to have this on a regular basis for all its operating markets. It is
essential management information and may also be helpful to inform communication
and engagement with government and other key stakeholders.’
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6.32
The separate disclosure of these types of payments would also increase
audit costs. Auditors consulted by the project team explained that
reaching an audit opinion on the accuracy and completeness of a
complete set of financial statements that included country-by-country
disclosure of different types of tax payments would require a more
precise and detailed (and costly) examination of those payments than if
the information were aggregated in the consolidated financial
statements as, for example, income tax expense or a production cost.
6.33
Despite these concerns about preparation, some entities have been
voluntarily reporting information about the payments they make to
governments. This suggests that those entities consider that the benefits
of publishing some of the types of information being proposed by PWYP
exceed the costs of preparation, noting though that the information may
not always be presented to the same level of detail as proposed by PWYP
and the information has not been audited. Some examples of such a
disclosure are provided at Exhibit 6.1 below.
Exhibit 6.1 – Disclosure of payments made to governments
2007 Fiscal Contributions to Host Governments1
Royalties
Canada
475
US
–
Taxes3
186
(2)
Total
661
(2)
UK
–
352
352
Netherlands
–
24
24
Norway
–
179
179
Denmark
4
10
14
Indonesia
391
183
574
Malaysia2
443
108
551
Vietnam2
6
8
14
Australia
3
83
86
Algeria
178
53
231
Tunisia
5
12
17
20
50
70
–
1
1
Trinidad and Tobago
Colombia
continued...
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...continued
Peru
–
Qatar
–
Other
–
1
1
1,525
1,248
2,773
Total Company
–
–
–
–
1
Not all of this expense represents cash payments to host governments.
Under certain contractual terms, royalties and taxes represent the
entitlement of the host government to a portion of production. Talisman
does not distinguish between cash payments and ‘commodity-based
payments’ in determining the Company’s total fiscal contribution to host
governments. Talisman recognizes such amounts at market prices in the
month the Company sells its share of production. With respect to other
material payments of $1 million or greater paid to governments, Talisman
paid $8 million to the government of Norway as a carbon tax, licence fee and
NOx fee. Talisman also paid the government of Indonesia a $1 million
signature bonus for the Sageri Exploration Block.
2
Royalties and taxes paid to the Government of Malaysia include the
Government of Vietnam’s share of the PM-3 CAA royalties and taxes. Royalties
represent cash payments and, in certain foreign operations, the entitlement
of the respective governments to a portion of Talisman’s share of production.
For additional information, see the Notes to Talisman Energy Inc.’s
Consolidated Financial Statements for the year ended December 31, 2007.
3
Taxes represent current tax expense and current production taxes.
Edited extracts from Talisman Energy, 2007 Corporate Responsibility
Report, page 34
Royalties and Taxes by Country for 2008 (Millions USD)
Australia
Government
Royalties
Taxes
Total
Percent
of Total
35.1
2.2
37.3
6%
Bolivia
5.3
1.1
6.4
1%
Ghana
13.5
0.1
13.6
2%
Indonesia
12.3
271.4
283.7
38%
0.8
4.3
5.1
1%
New Zealand
Peru
0.1
207.6
207.7
29%
USA
0.0
166.5
166.5
23%
Total
67.1
653.2
720.3
100%
Edited extract from Newmont Mining Corporation, Beyond the Mine (the
Newmont Sustainability Report 2008)*
*
Accessed from: http://www.beyondthemine.com/2008/?l=2&pid=4&parent=17&id=144
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Confidentiality concerns
6.34
The disclosure of tax payments on a country-by-country basis may breach
confidentiality agreements that the entity has with a government.
The concern is that by disclosing this information, the entity may
contravene the undertakings it has made with a government and face the
risk of losing its assets (through expropriation) in that country.
6.35
Research undertaken for PWYP by the Columbia Law School provides a
different perspective on these confidentiality concerns.* After surveying
over 150 minerals and oil and gas contracts between host governments
and minerals and oil and gas entities, the research found that the
confidentiality clauses were quite similar. Most clauses indicated that no
party to the contract could disclose any information flowing from the
contract without the written consent of the other parties, but typically
the clauses include some standard exceptions that would permit the
disclosure of information for compliance with the law and regulations.
This would include compliance with IFRSs in those jurisdictions that
incorporate IFRSs into their law or regulations.
6.36
A concern that has been raised by some preparers in response is that an
entity may be discouraged from disclosing this information, even if its
contract with a host government indicates that it is legally permissible to
do so. The concern is that if either the host government, or the
administrator of the contract on behalf of the host government, did not
want the information to be disclosed, then the entity might lose future
investment opportunities in that country to other entities that are not
required to make that disclosure. Entities might also be concerned about
the risk to its existing assets if its contracts had to be renewed or
renegotiated. Whether either concern eventuates, however, would seem
to depend on whether the economic significance of the entity’s
operations in that country would require separate disclosure and the
ability for the government to take over the entity’s operations or award
them to other entities that are not required to make the same disclosures.
6.37
Both the research from the Columbia Law School and the concerns raised
by preparers demonstrate that the ability of an entity to disclose this
information will depend on the individual facts and circumstances of
each case. The project team does not consider that the existence of
confidentiality clauses that may prevent this level of disclosure in
particular cases, or the perceived threat of the loss of existing assets or
future opportunities that may discourage such disclosure, justifies not
*
This research is published in Rosenblum P and Maples S, Contracts Confidential: Ending
Secret Deals in the Extractive Industries, Revenue Watch Institute, 2009.
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requiring this information to be provided. Instead, one approach could
be to require the disclosure subject to an exemption similar to that in
IAS 37 Provisions, Contingent Liabilities and Contingent Assets, which as
explained in Chapter 5 provides an exemption in cases when disclosing
the required information could be expected to prejudice seriously the
position of the entity. In genuine cases where the disclosure of payments
to governments is considered either to breach confidentiality
requirements that a host government is expected to enforce or is
expected to prejudice seriously the position of the entity for other
reasons, the project team recommends that the entity should disclose
why it is unable to disclose the information.
PWYP disclosure 2: Reserves
6.38
PWYP is proposing the country-by-country disclosure of reserve quantities
and reserve valuation (if required by the IFRS).
Reserve quantities
6.39
As outlined in Chapter 5, the project team proposes the disclosure of
minerals or oil and gas proved and probable reserve quantities. These
reserve quantities should generally be separately disclosed at an
individual country level because most of the non-geological risks
associated with reserves are country-specific. When individual properties
are material to the entity, the project team proposes that reserves
quantities should be disclosed by property. The only difference from the
PWYP proposals that would result in less information being disclosed is
that the project team considers that a regional aggregation of reserve
quantities is acceptable if the reserves attributable to a country are not
material to the entity. This difference arises as a consequence of the
materiality constraint that applies to financial reporting information.
Reserve values
6.40
Users indicated that if a reserves valuation—being a current value
measurement of minerals or oil and gas properties, such as a fair value
estimate or a standardised measure of discounted future cash flows—is
disclosed, it should be presented on a disaggregated basis rather than as
a single entity-wide valuation. Many users acknowledged that, in
principle, the valuation should be disclosed at the same level of detail as
reserve quantities, but said that the costs of preparing and presenting this
valuation at this level of detail might exceed the benefits they would
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derive from this information. Users accepted that disclosing this
information by major geographical region might be sufficient for their
needs. However, this disclosure would not be sufficiently detailed to be
useful to PWYP.
PWYP disclosure 3: Production quantities
6.41
PWYP is proposing the country-by-country disclosure of production
quantities for the current reporting period. Additional disclosure by key
products and key properties is encouraged.
6.42
In Chapter 5, the project team proposes that current period production
quantities should be disclosed as part of a reconciliation of changes
between the opening and closing estimates of reserve quantities.
The reconciliation is to be disclosed at the same level of detail as the
disclosure of reserve quantities and would identify the produced
quantities by commodity. Reserves quantities, and therefore production
quantities, would be shown by country (or property) where that is
material to the entity. Consequently, the project team’s proposals would
not include separate disclosure of production quantities by country
where those reserves were not material to the entity.
PWYP disclosure 4: Production revenues
6.43
The project team does not propose that production revenues should be
disclosed on a country-by-country basis. As noted in Chapter 5,
production revenue information is usually more relevant to capital
providers if it is separately presented by commodity rather than by
country. This is because production revenue is typically affected by
commodity market factors that are generally international in nature.
For this reason, the project team proposes that production revenue
should be disclosed by commodity. Usually, disclosure of production
revenue by country is useful to capital providers only when the
commodity price is influenced by domestic factors (eg domestic gas sales).
The project team therefore considers that the incremental benefit to
capital providers of requiring the disclosure of production revenues by
country would be small if information on production quantities is
disclosed by country.
6.44
An entity’s segment disclosures may provide some further detail on
production revenues by possibly separately identifying sales to external
customers from inter-entity transfers of the produced commodity to the
entity’s downstream operations. However, these disclosures are likely to
be presented by commodity or business group rather than by country.
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PWYP disclosure 5: Development and production costs
6.45
The project team proposes that the exploration, development and
production costs incurred over a period of, say, five years should be disclosed
to provide users with a time series of these cash outflows. This cost
information would be disclosed at the same level as the reserve quantities
information and therefore would not include separate disclosure of costs by
country where the reserves were not material to the entity.
PWYP disclosure 6: Disclosure of key subsidiary and property
information
6.46
The final PWYP proposal is for country-by-country disclosure of the names
of key subsidiaries and the locations of key minerals or oil and gas
properties. IFRSs, through IAS 24 Related Party Disclosures and IAS 27
Consolidated and Separate Financial Statements, already require the disclosure
of information about an entity’s significant investments in subsidiaries.
This requirement is comparable to the PWYP disclosure proposal.
6.47
The project team’s research showed that information about the locations
of key minerals or oil and gas properties is typically available in the
management commentary section of annual reports or in other
information issued by minerals and oil and gas entities, such as project
factbooks. In addition, paragraph 138(b) of IAS 1 requires an entity to
disclose a description of the nature of its operations and its principal
activities, if that information is not disclosed elsewhere in information
published with its financial statements. The project team thinks that
these existing disclosures are sufficient for communicating the nature of
an entity’s operations in countries that are material to the entity. These
disclosures would not specify the properties or operations that belong to
individual subsidiaries within each country, but information at this level
of detail has not been identified by capital providers as being necessary to
make informed investment decisions. Accordingly, the project team does
not propose that information by subsidiary should be required.
Summary
6.48
On the basis of this analysis, country-specific information would be
expected to be disclosed for reserve quantities, production quantities,
development and production costs, together with a listing of key
subsidiaries where that information is material to the entity.
The disclosure of reserve values and production revenues would also be
disclosed, but it is not expected to be on a country-by-country basis.
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6.49
The disclosure of payments to governments is not addressed either in
IFRSs or the project team’s disclosure proposals in Chapter 5. The project
team has undertaken a preliminary review of the cost-benefit
implications of disclosing payments to governments. The research shows
that the disclosure of payments made to governments provides
information that would be used by at least some capital providers in
making their investment decisions, either by using the information to
make their own assessments of investment risks and reputational risk or
by providing better information to other risk analysts that advise the
capital providers on investment and reputational risks.
6.50
Preparers have suggested that there would be a significant cost associated
with disclosing information about payments made to governments.
Preparers also raised concerns about the materiality of this information,
both in terms of providing the disclosure on a country-by-country basis
and the separate disclosure by payment type.
6.51
The project team notes that further study is required to conclude on
whether the country-by-country disclosure of payments to governments
is justifiable on cost-benefit grounds. This cost-benefit assessment could
take into account the disclosure of all payments to governments or
alternatively the disclosure of those types of payments to governments
that are both significant and readily observable from the entity’s
financial records. To help with this assessment, additional comments on
the cost-benefit implications of payments to governments are requested
in response to this discussion paper.
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Appendix A
Description of extractive activities
Minerals industry
Oil and gas industry
Prospecting
Prospecting generally covers a large area and involves searching
for a geological anomaly or structure that might warrant
detailed exploration. Prospecting usually involves researching
and analysing historical geological data and carrying out
topographical, geological and geophysical studies. Some
industry participants do not distinguish between prospecting
and exploration activities.
Exploration
Exploration is the detailed examination of a geographical area
of interest that has shown sufficient mineral-producing
potential to merit further exploration. Exploration activities
include:
• conducting topographical, geological, geochemical and
geophysical studies; and
• carrying out exploratory drilling, trenching and sampling
activities.
Exploration activities are
undertaken to define and
delineate a specific ore body
and to determine the quantity,
mineralogical nature and
grade of the ore. In hard
metals mining, exploration
usually involves taking cores
for analysis, sinking
exploratory shafts, geological
mapping, geochemical
analysis, cutting drifts and
crosscuts, opening shallow
pits, and removing overburden
in some areas.
Exploration activities are
undertaken to examine in
greater detail geological
structures that have been
identified as potential oilbearing or gas-bearing
formations to determine
whether minerals may be
present in commercial
quantities. Exploration of
potential oil-bearing or
gas-bearing structures
employs techniques such as
seismograph shooting, core
drilling and the drilling of an
exploratory well.
continued...
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...continued
Minerals industry
Evaluation
Oil and gas industry
Evaluation activities involve determining the technical
feasibility and commercial viability of mineral deposits that
have been found through exploration.
Evaluation activities include:
Evaluation activities include:
• drilling, trenching and
sampling activities to
determine the quantity
and grade of the deposit;
• drilling appraisal wells to
gain additional
information about the size
and characteristics of the
reservoir;
• examining and testing
• detailed engineering
extraction methods and
studies to determine how
metallurgical or treatment
best the reservoir can be
processes; and
developed to obtain
• detailed economic
maximum recovery; and
feasibility evaluations to
• detailed economic
determine whether
evaluations to determine
development of the
whether development of
reserves is commercially
the reserves is
justified and to plan
commercially justified.
methods for mine
development.
Development
Development is the establishment of access to the mineral
reserve and other preparations for commercial production.
Development activities often continue during production.
Development activities
include:
Development activities
include:
• gaining access to and
• sinking shafts and
preparing well locations
underground drifts (often
for drilling;
called mine development);
continued...
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...continued
Minerals industry
Oil and gas industry
• making permanent
excavations;
•
constructing platforms or
preparing drill sites from
which to drill wells to gain
access to and produce the
oil and gas reserves;
•
drilling wells to gain
access to and produce the
oil and gas reserves; and
•
installing equipment and
facilities necessary for
bringing the oil and gas to
the surface and for
handling, storing, and
processing or treating the
oil and gas to make them
marketable or
transportable.
• developing passageways
and rooms or galleries;
• building roads and
tunnels; and
• advance removal of
overburden and waste
rock.
Development (or construction)
also includes the installation
of infrastructure (eg roads,
utilities and housing),
machinery, equipment and
facilities.
Production
Production involves the extraction of the natural resources
from the earth and the related processes necessary to make the
produced resource marketable or transportable.
Depending on the materials
removed from the earth and its
mineral content, many
different processes may be
used to convert the ore or
other raw product removed
from the earth into a
marketable product. Crushing
and grinding, flotation,
leaching, heap leach, milling,
settling, and electrowinning
are some of the processes
commonly used to remove the
saleable mineral from the
mined ore or rock.
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Production activities include
lifting the oil or gas to the
surface, gathering production
from individual wells to a
common point in the field,
field treating, field processing
(eg the removal of impurities
and the separation of oil and
gas necessary to make the
product marketable or
transportable), and storage of
the production in field storage
tanks.
EXTRACTIVE ACTIVITIES
Appendix B
Overview of minerals and oil and gas reserves and
resources definitions
B1
This appendix provides an overview of the following sets of reserve and
resource definitions:
(a)
the International Reporting Template for the Public Reporting of
Exploration Results, Minerals Resources and Mineral Reserves (the
CRIRSCO Template);
(b)
the Petroleum Resource Management System;
(c)
the US SEC mineral reserve and oil and gas reserve definitions; and
(d)
the United Nations Framework Classification for Fossil Energy and
Mineral Resources.
The CRIRSCO Template
B2
CRIRSCO is a Task Force of the International Council for Mining and
Metals that is responsible for promoting and maintaining best practice
reporting of mineral deposit estimates (ie mineral reserves and resources)
and exploration progress (ie exploration results). In July 2006 CRIRSCO
published the International Reporting Template for the Public Reporting of
Exploration Results, Minerals Resources and Mineral Reserves (‘the CRIRSCO
Template’).
B3
The CRIRSCO Template is a consolidated version of the following national
reporting codes:
(a)
the Australasian Code for Reporting of Mineral Resources and Ore Reserves
(the JORC Code) ;*
(b)
in Canada, the CIM Definition Standards on Mineral Resources and
Mineral Reserves (the CIM Code);†
(c)
in Chile, the Certification Code For Exploration Prospects, Mineral
Resources And Ore Reserves;§
*
Prepared by the Joint Ore Reserves Committee of the Australasian Institute of Mining
and Metallurgy, Australian Institute of Geoscientists and Minerals Council of Australia.
†
Prepared by the Canadian Institute of Mining, Metallurgy and Petroleum’s Standing
Committee on Reserve Definitions.
§
Prepared by the Mineral Resources Committee of the Institution of Mining Engineers of
Chile.
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(d)
the Pan–European Code for Reporting of Exploration Results, Mineral
Resources And Reserves (the PERC Reporting Code);*
(e)
in Peru, the Code for Reporting of Mineral Resources and Ore Reserves;†
(f)
the Philippine Mineral Reporting Code for Reporting of Exploration Results,
Mineral Resources and Ore Reserves;§
(g)
the South African Code for the Reporting of Exploration Results, Mineral
Resources and Mineral Reserves (the SAMREC Code);ø and
(h)
in the United States, A Guide for Reporting Exploration Information,
Mineral Resources, and Mineral Reserves (the SME Code).‡
The definitions in the CRIRSCO Template are either identical to, or not
materially different from, the definitions in those national reporting
codes.#
B4
The CRIRSCO Template (and each of the national reporting codes)** sets
out a framework for classifying tonnage and grade estimates of a mineral
deposit according to the levels of geological confidence and degree of
technical and economic evaluation. The primary classifications are
‘mineral resources’ and ‘mineral reserves’.
A classification for
*
Prepared by the Pan-European Reserves and Resources Reporting Committee (PERC).
†
Prepared by the Joint Committee of the Venture Capital Segment of the Lima Stock
Exchange.
§
Prepared by the PMRC Committee composed of the Philippine Minerals Development
Institute Foundation, Philippine Society of Mining Engineers, Geological Society of the
Philippines, Society of Metallurgical Engineers of the Philippines, Mines and
Geosciences Bureau, The Philippine Stock Exchange, Inc., Board of Investments,
Chamber of Mines of the Philippines and the Philippine Australia Business Council.
ø
Prepared by the South African Mineral Resource Committee (SAMREC) Working Group
under the Joint Auspices of the Southern African Institute of Mining and Metallurgy
and the Geological Society of South Africa.
‡
Prepared by the Resources and Reserves Committee of the Society For Mining,
Metallurgy And Exploration, Inc.
#
International Reporting Template for the Public Reporting of Exploration Results, Minerals Resources
and Mineral Reserves (CRIRSCO Template), CRIRSCO, July 2006, page 2.
**
The CRIRSCO Template is identified as a ‘template’ rather than a ‘code’ because, at
present, it is intended to be used to assist jurisdictions to produce their own national
reporting codes that are consistent with international best practice. In contrast, the
national reporting codes are in most cases incorporated into that country’s securities
regulations or stock exchange listing rules to prescribe the basis for the public
disclosure of reserve, resource and exploration progress information.
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‘exploration results’, which is a precursor to resources and reserves, is
also included.
The relationship between these classifications is
illustrated by the following diagram and discussed further in the
paragraphs below.*
Figure B.1
Exploration
Results
Mineral
Resources
Increasing Level
of Geoscientific
Knowledge
and Confidence
Mineral
Reserves
Inferred
Indicated
Probable
Measured
Proved
Consideration of mining, metallurgical, economic, marketing, legal,
environmental, social and governmental factors.
(the “Modifying Factors”)
Resource definitions
B5
The CRIRSCO Template defines a ‘mineral resource’ as:
a concentration or occurrence of material of economic interest in or on the
Earth’s crust in such form, quality and quantity that there are reasonable
prospects for eventual economic extraction. The location, quantity, grade,
continuity and other geological characteristics of a Mineral Resource are
known, estimated or interpreted from specific geological evidence, sampling
and knowledge.†
B6
Although a mineral resources estimate is based on predominantly
geoscientific information, the CRIRSCO Template explains that the
mineral resources classification does not represent an inventory of all
mineralisation that has been drilled or sampled. Instead, it is a realistic
inventory of mineralisation that might, in whole or in part, become
*
CRIRSCO Template, Figure 1
†
CRIRSCO Template, clause 19
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DISCUSSION PAPER MARCH 2010
economically extractable under assumed and justifiable technical and
economic conditions. Consequently, any portions of a mineral deposit
that do not have reasonable prospects for eventual economic extraction
are not to be included as a mineral resource.
B7
The mineral resources classification is subdivided into the following
three categories according to the level of geological confidence associated
with the resources estimate:
(a)
a ‘measured mineral resource’ is that part of a mineral resource for
which tonnage, densities, shape, physical characteristics, grade and
mineral content can be estimated with a high level of confidence;
(b)
an ‘indicated mineral resource’ is that part of a mineral resource
for which tonnage, densities, shape, physical characteristics, grade
and mineral content can be estimated with a reasonable level of
confidence; and
(c)
an ‘inferred mineral resource’ is that part of a mineral resource for
which tonnage, grade and mineral content can be estimated with a
low level of confidence.
Reserve definitions
B8
Mineral reserves are derived from a mineral resources estimate.
The CRIRSCO Template defines a ‘mineral reserve’ as:
the economically mineable part of a Measured and/or Indicated Mineral
Resource. It includes diluting materials and allowances for losses, which may
occur when the material is mined. Appropriate assessments and studies have
been carried out, and include consideration of and modification by realistically
assumed mining, metallurgical, economic, marketing, legal, environmental,
social and governmental factors. These assessments demonstrate at the time of
reporting that extraction could reasonably be justified.*
B9
*
The assessments and studies described in the mineral reserves definition
are generally referred to as feasibility studies, noting that some entities
will prepare both a pre–feasibility study (or preliminary feasibility study)
and feasibility study (or final feasibility study). It is the content of the
feasibility study (rather than its name) that enables the reserves
classification to be satisfied. In either case, the objective of a feasibility
study is to produce a mine plan that indicates that extraction of the
minerals would be technically achievable and economically viable. This
mine plan is used in deriving the mineral reserves estimate.
CRIRSCO Template, clause 28
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B10
Mineral reserves are subdivided into proved reserves and probable
reserves. These reserves categories are derived from the measured and
indicated resources categories.
(a)
‘Proved reserves’ represent:
(i)
the economically mineable part of a measured resource (ie a
high level of confidence in the geology of the underlying
resource); and
(ii)
a similarly high level of confidence in the reserves estimate
after considering the effect of the modifying factors (ie
mining, metallurgical, economic, marketing, legal,
environmental, social and governmental factors) on the
estimate.
For some mineral deposits, classification as proved reserves may
not be possible because, for example, the erratic distribution of the
mineralisation throughout the deposit means that it is not possible
or feasible to classify the deposit as a measured resource. In other
cases, the proved reserves classification will not be satisfied if the
collective effect of the modifying factors that are considered when
converting a resource to a reserve result in the reserves estimate
having a lower level of confidence than the corresponding
measured resources estimate.
(b)
B11
‘Probable reserves’ are either:
(i)
the economically mineable part of an indicated mineral
resource (ie a reasonable level of confidence in the geology of
the underlying resource); or
(ii)
the economically mineable part of a measured resource in
those circumstances when the proved reserve classification
cannot be satisfied.
There are no mineral reserves classifications that are derived from the
inferred resources classification. This is because there is insufficient
knowledge of the geometry, grade and continuity of the mineral deposit
to be able to apply the modifying factors to an inferred resource such that
there is confidence in the outcome.
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Exploration results
B12
Exploration results include data and information generated by
exploration programs that may be of use to investors but that do not
satisfy the definitions of mineral resources or mineral reserves. This is
common in the early stages of exploration when the quantity of data
available is generally not sufficient to allow any reasonable estimates of
tonnage and grade to be made.
Estimate preparation
B13
The CRIRSCO Template is regarded as being a principle-based
classification system. It provides a framework for classifying estimates of
reserves, resources and exploration results but does not prescribe in
detail how those estimates are to be prepared. This is because it is not
considered feasible to develop detailed rules to prescribe the techniques
and assumptions that must be used in estimating reserves and resources
for each individual commodity. Instead, the approach adopted in the
CRIRSCO Template (and by the national reporting codes) is to require that
the estimates be prepared by ‘competent persons’, who are suitably
qualified and experienced individuals subject to an enforceable
professional code of ethics and rules of conduct.*
The PRMS
B14
The Petroleum Resource Management System (PRMS), published in March
2007, revised the previous reserves and resources definitions that had
been published in 1997 and 2000 respectively. The PRMS was developed
by the SPE Oil and Gas Reserves Committee, a standing committee of the
SPE. Of the sponsors of the PRMS, the SPE, AAPG and SPEE are leading
professional organisations in the oil and gas industry and the WPC is the
international organisation that represents all aspects of the oil and gas
industry.
B15
The PRMS is designed to provide a common reference for the
international oil and gas industry, including national reporting and
regulatory disclosure agencies, and to support oil and gas project and
portfolio management requirements†. From a regulatory disclosure
perspective, the PRMS definitions are proposed to be incorporated into
*
For further information, see CRIRSCO Template clauses 7–10 and accompanying
commentary.
†
Petroleum Resource Management System (PRMS), SPE, 2007, page 1
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the oil and gas disclosure requirements of the Australian Securities
Exchange* and are incorporated in the admission requirements for oil
and gas entities listing on the London Stock Exchange’s Alternative
Investment Market.† Although the PRMS is not directly referenced in
other regulatory disclosure requirements at this time (despite being
widely accepted in the industry for internal management purposes and
having been voluntarily adopted by some entities in their public
disclosure of reserve or resource quantity estimates), it is:
B16
(a)
very closely aligned with the oil and gas reserves and resources
definitions used in conjunction with the Canadian Securities
Administrators’ National Instrument 51–101 Standards of Disclosure
for Oil and Gas Activities;§
(b)
comparable to the revised SEC oil and gas reserves definitions in
Regulation S-X, Rule 4–10 issued in 2008 (see paragraph B25 for
further details).
The PRMS refers to all types of oil and gas as petroleum.ø It classifies all
quantities of petroleum naturally occurring on or within the Earth’s
crust. Consequently, it classifies quantities of petroleum that have been
discovered, quantities that are as yet undiscovered, and quantities that
have already been produced. The classifications that will be of most
relevance to financial reporting relate to estimates of quantities of
petroleum that are discovered and recoverable, but have not yet been
produced. This includes the classifications of reserves and contingent
resources.
*
Australian Securities Exchange, Exposure Draft Proposed ASX Listing Rule Amendments,
20 June 2007, proposed Listing rule 5.6A
†
London Stock Exchange Alternative Investment Market, Guidance Note for Mining, Oil and
Gas Companies, March 2006
§
NI 51–101 cross refers to the reserve and resource definitions incorporated in the
Canadian Oil and Gas Evaluation Handbook (COGEH) that is prepared jointly by The
Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute
of Mining, Metallurgy & Petroleum (Petroleum Society). Section 5.1.1 of COGEH notes
that ‘There is now a broad alignment between COGEH and SPE-PRMS definitions and
guidelines, but some minor differences remain’. Other industry participants have
noted that the PRMS and COGEH are ‘very closely aligned’ and ‘very similar’ – see, for
example, http://www.sec.gov/comments/s7-29-07/s72907-29.pdf and http://www.sec.gov/
comments/s7-29-07/s72907-82.pdf.
ø
Petroleum is defined in the PRMS, at page 2, as ‘a naturally occurring mixture
consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also
contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen,
hydrogen sulfide and sulfur.’
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B17
The relationship between these classifications in the PRMS is illustrated
by the following diagram and discussed further in the paragraphs below.*
Figure B.2
Operational and Economic Status
Project Maturity
Sub-classes
Potentially
Commercial
PROSPECTIVE
RESOURCES
Development Pending
Development Unclarified
or On Hold
Development
not Viable
Prospect
Lead
Play
Lower Risk
Justified for
Development
Project Maturity
CONTINGENT
RESOURCES
Approved for
Development
Higher Risk
Increasing Chance of Commerciality
Developed
Commercial
Undeveloped
Marginal
Sub-Marginal
DISCOVERED IIP
Sub-Commercial
On Production
RESERVES
UNRECOVERABLE
UNDISCOVERED IIP
TOTAL PETROLEUM INITIALLY-IN-PLACE (IIP)
PRODUCTION
UNRECOVERABLE
Not to scale
Range of Uncertainty
Reserves definitions
B18
‘Reserves’ are defined as:
those quantities of petroleum anticipated to be commercially recoverable by
application of development projects to known accumulations from a given
date forward under defined conditions. Reserves must further satisfy four
criteria: they must be discovered, recoverable, commercial, and remaining
(as of the evaluation date) based on the development project(s) applied.†
*
CRIRSCO and SPE OGRC, Mapping of Petroleum and Minerals Reserves and Resources
Classification Systems (the Mapping Report), September 2007, Figure 2. (This diagram is
based on a draft depiction of the PRMS. The corresponding depictions of the PRMS in
Petroleum Resource Management System (2007) are presented at figure 1-1 and figure
2-1 of that document.)
†
PRMS, section 1.1
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B19
B20
Reserves are categorised as either proved, probable or possible reserves in
accordance with the level of certainty associated with the estimates.
(a)
‘Proved reserves’ refers to those quantities of petroleum that can be
estimated with reasonable certainty to be commercially recoverable
from known reservoirs and under defined economic conditions,
operating methods, and government regulations. ‘Reasonable
certainty’ is intended to express a high degree of confidence that the
quantities will be recovered (if deterministic estimation methods are
used) or that there should be at least a 90 per cent probability that
the quantities actually recovered will equal or exceed the estimate
(if probabilistic estimation methods are used).
(b)
‘Probable reserves’ have an equal likelihood that actual remaining
quantities recovered will be greater than or less than the sum of
the estimated proved plus probable reserves (2P). In this context,
there should be at least a 50 per cent probability that the actual
quantities recovered will equal or exceed the 2P estimate
(if probabilistic estimation methods are used).
(c)
‘Possible reserves’ refers to those additional reserves that are less
likely to be recoverable than probable reserves. With possible
reserves, there is a low probability that the total quantities
ultimately recovered from the project will exceed the sum of
proved plus probable plus possible (3P) reserves. In this context,
there should be at least a 10 per cent probability that the actual
quantities recovered will equal or exceed the 3P estimate
(if probabilistic estimation methods are used).
Reserves can also be characterised by their project maturity and/or
development and production status. For reserves estimates, the PRMS
identifies project maturity subclassifications relating to the business
decisions required to move a project towards commercial production.
These subclassifications are: ‘on production’; ‘approved for development’;
and ‘justified for development’. Subdivisions of the reserves estimate by
development and production status are based on the funding and
operational status of the wells and associated facilities within the
reservoir development plan. These subdivisions are: ‘developed reserves’,
which can be further subdivided into ‘developed producing reserves’ and
‘developed non-producing reserves’; and ‘undeveloped reserves’. Broadly
speaking, characterising reserves by project maturity or by the status of
the reserves can be useful for assessing the risks associated with the
project and for forecasting the timing of cash flows associated with
future production of oil and gas.
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Resource definitions
B21
‘Contingent resources’ are defined as:
those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from known accumulations, but the applied project(s) are not yet
considered mature enough for commercial development due to one or more
contingencies. Contingent Resources may include, for example, projects for
which there are currently no viable markets, or where commercial recovery
is dependent on technology under development, or where evaluation of the
accumulation is insufficient to clearly assess commerciality.*
B22
Like reserves, contingent resources are further categorised in accordance
with the level of certainty associated with the estimates. Contingent
resources can also be characterised by their project maturity and/or by
their economic status. For contingent resource estimates, the project
maturity subclassifications are: ‘development pending’; ‘development
unclarified or on hold’; and ‘development not viable’. The economic
status of contingent resources estimates can be classified as:
(a)
‘marginal contingent resources’, which are defined as those
quantities associated with technically feasible projects that are
either currently economic or projected to be economic under
reasonably forecast improvements in commercial conditions but
are not committed for development because of one or more
contingencies; and
(b)
‘sub-marginal contingent resources’, which are defined as those
quantities associated with discoveries for which analysis indicates
that technically feasible development projects would not be
economic and/or other contingencies would not be satisfied under
current or reasonably forecast improvements in commercial
conditions. The PRMS advises that these projects nonetheless
should be retained in the inventory of discovered resources
pending unforeseen major changes in commercial conditions.†
The US SEC definitions
B23
The US SEC has developed rules that govern the definition and disclosure of
mineral reserves and oil and gas reserves by SEC registrants. Separate
definition and disclosure requirements exist for minerals and for oil and gas.
*
PRMS, section 1.1
†
Classifying reserve and resource estimates by project maturity was a feature of the SPE’s
previous oil and gas reserve and resource definitions. Classifying resource estimates by
economic status is a feature that was introduced with the PRMS, and therefore may not
be widely adopted at present.
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B24
SEC Industry Guide 7 Description of property by issuers engaged or to be engaged
in significant mining operations contains the definitions of mineral reserves,
proven reserves and probable reserves. Industry Guide 7 does not define
mineral resources because it generally prohibits the disclosure of
estimates other than proved or probable reserves. The exceptions to this
prohibition are if this information is required to be disclosed by foreign
or state law or where such estimates have been previously provided to a
person (or any of its affiliates) that is offering to acquire, or to merge or
consolidate with, the registrant or otherwise to acquire the registrant’s
securities.
B25
SEC Regulation S-X, Rule 4-10 Financial accounting and reporting for oil and gas
producing activities pursuant to the Federal Securities Laws and the Energy Policy
and Conservation Act of 1975 contains the definitions of oil and gas reserves.
This rule was revised on 29 December 2008. The SEC made the revisions
after considering public comments in response to both a Concept Release
(issued for comment in December 2007) and a Rule Proposal (issued for
comment in June 2008). The revisions to this rule have resulted in the
definitions of:
(a)
proved reserves, developed reserves and undeveloped reserves being
updated to correspond more closely with current best practices in
reserves estimation;
(b)
probable reserves and possible reserves being added as a
consequence of the revisions to the SEC disclosure requirements
permitting, but not requiring, the disclosure of probable and
possible reserves quantities; and
(c)
oil and gas reserves now including oil and gas extracted from oil
sand, shale, and coal beds. Before the revisions, the extraction of
oil and gas from oil sands deposits was regarded as a mining
operation with oils sands reserves to be disclosed as minerals
reserves.
As a consequence of these revisions, the SEC oil and gas reserves
definitions are now generally regarded as being broadly comparable to
the reserves definitions in the PRMS. (The SEC definitions generally
require historical commodity prices to be used in preparing reserves
estimates.* Although the PRMS prefers the use of the entity’s reasonable
forecast of future prices, it also permits the use of historical prices.†)
*
See paragraph 5.53 for further details.
†
See PRMS, section 3.1.2.
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B26
The revisions also indicate that the disclosure of oil and gas resources
quantities is still prohibited in SEC filings, although a definition of oil
and gas resources has been added as part of the SEC revisions. This
definition appears to be included for completeness. It indicates that
resources include both discovered and undiscovered accumulations that
are either estimated to be recoverable or unrecoverable. Consequently,
this definition is too broad to be suitable for supporting accounting or
disclosure requirements.
The UNFC
B27
The United Nations Framework Classification for Fossil Energy and
Mineral Resources (UNFC) is ‘a universally applicable scheme for
classifying petroleum and solid mineral (including energy mineral)
reserves and resources. The Classification is designed to allow the
incorporation of currently existing terms and definitions into this
framework and thus to make them comparable and compatible.* It is
designed to be a classification system capable of communicating
information on fossil energy and mineral quantities that can meet the
needs of:
(a)
long-sighted energy (and mineral) policies, which relates to the
need to produce international mineral and energy studies in
support of long-sighted and robust policies and strategies;
(b)
government resources management, which relates to the needs of
governments in implementing their policies through their
resource management;
(c)
corporate business process management, which relates to the
needs of industry and in managing their business processes to
serve their host countries, shareholders and stakeholders; and
(d)
financial reporting, which relates to the needs of the financial
community for allocating capital efficiently so as to reduce capital
costs to a minimum.
In that regard, the UNFC is designed to classify in-place and recoverable
quantities ranging from those that are being produced through to those
that may (eventually) be produced but are as yet undiscovered
(ie prospective resources) in a manner that meets the needs listed above.
*
UNECE Ad Hoc Group of Experts on Harmonization of Fossil Energy and Mineral
Resources Terminology Report of the Task Force on Mapping of the United Nations Framework
Classification for Fossil Energy and Mineral Resources, 8 April 2008, page 7.
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B28
The UNFC for minerals was recommended to be used by UN member
states in 1997 and has been legislated in mineral-producing countries
such as India and Ukraine. It was adapted to oil and gas in 2004.
Accordingly, the UNFC is the only known classification that harmonises
the main minerals and oil and gas classifications and is recognised and
recommended for global use.
B29
A revised version of the UNFC was issued in 2009 that, among other
things, enables the CRIRSCO Template and the PRMS to be mapped closely
to it. This means that, for example, entities providing reserve and
resource disclosures that are consistent with the CRIRSCO Template and
the PRMS definitions should be able to express them according to the
classifications in the UNFC system.
B30
The detailed formulation of the UNFC is being further developed jointly by
CRIRSCO, SPE/WPC/AAPG/SPEE and a broad group of stakeholders. Part of
the work consists of fine-tuning the classification to the needs that it is
meant to serve. Financial reporting is one of them. Work is also under way:
(a)
to consider developing specifications (ie secondary rules) to meet
stakeholder requirements; and
(b)
to determine the long-term governance model for the UNFC.
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Appendix C
User survey process
Purpose of the user survey
C1
The survey was conducted to seek input from financial reporting users on:
(a)
how historical cost information on reserves and resources currently
included in financial statements is used by users;
(b)
how current value information on minerals and oil and gas
reserves and resources included in financial statements might be
used by users;
(c)
attributes that should be included in a current value measurement
of a minerals or oil and gas deposit for financial reporting purposes
so that it would be useful to users;
(d)
information that should be disclosed in financial statements to
provide support for a current value measurement; and
(e)
usefulness of a current value measurement relative to existing
historical cost measurement models.
Number of responses
C2
A total of 34 users were surveyed over the period from late February 2007
to early May 2007. All surveys were conducted either as face-to-face
interviews or as telephone interviews.
User profile
C3
The following types of users were interviewed:
(a)
(b)
users who cannot command
information—specifically:
tailored
financial
(i)
buy-side analysts/fund managers: six interviews;
(ii)
sell-side analysts: 21 interviews; and
reporting
users who can command tailored financial reporting information
but usually begin their analysis with publicly available
information—specifically:
(i)
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(ii)
lenders: three interviews; and
(iii)
debt-ratings agencies: two interviews.
C4
The user survey interviewees were drawn from Australia, Canada, South
Africa, the United Kingdom and the United States. The responses from
the users surveyed therefore provide insights to the usefulness of the
different types of information generated by minerals and oil and gas
entities reporting in different jurisdictions. The users surveyed have a
mix of backgrounds (eg as a geologist or a finance professional), and
market specialisations (minerals or oil and gas, large producers or small
explorers, specific minerals etc) and generally have 10 or more years’
experience in analysing minerals or oil and gas entities.
C5
As part of the user survey, the research project team also had informal
discussions with certain market and securities regulators including staff
from the United States Securities and Exchange Commission, the Ontario
and Alberta Securities Commissions, and the Johannesburg Stock
Exchange.
Survey questions
C6
The user survey questions addressed the following topics:
(a)
the investment and lending decision process, including:
(i)
the minimum information that users need to make informed
investment or lending decisions in relation to a mining or oil
and gas entity;
(ii)
the extent to which the information needs differ depending on:
(iii)
(b)
(A)
whether the entity is involved only in exploration
activities, upstream activities or upstream and
downstream activities; and
(B)
the type of mineral, oil or gas involved;
the sources of this information, such as financial statements,
management commentary and the entity’s website;
the usefulness of existing reporting practices, including:
(i)
whether measuring mineral or oil and gas property assets in
the statement of financial position at their historical costs
provides useful information; and
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(ii)
(c)
whether measuring mineral or oil and gas property assets
acquired in a business combination at their fair value
provides useful information;
the current value measurement of mineral or oil and gas property
assets, including:
(i)
the advantages and disadvantages of presenting a current
value measurement in the statement of financial position
(and which would be supplemented by disclosures to help
users understand the measurement) compared with
providing only value-based information disclosures;
(ii)
the most appropriate model for valuing these assets
(eg discounted cash flow models);
(iii)
whether the current value measurement should assign value
to the entire deposit or exclude value attributable to some
categories of reserves or resources;
(iv)
whether development works and infrastructure assets should
be recognised separately from the minerals or oil and gas
property asset;
(d)
when the mineral or oil and gas property assets should initially be
measured at current value (eg at acquisition of the exploration
rights, discovery or project approval) and how frequently should
the asset be remeasured (eg each reporting period, each annual
reporting period or only when a significant event has occurred);
(e)
the level of detail (or disaggregation) associated with presenting
the current value measurement and disclosing the supporting
information and assumptions, such as reserve and resource
volumes, that provides useful information and should be practical
to prepare;
(f)
the disclosure of supporting information and assumptions,
including:
(i)
which categories of minerals or oil and gas reserve and
resource quantities should be disclosed;
(ii)
whether the assumptions used for commodity prices,
exchange rates and discount rates should be either a market
participant’s assumptions, entity-specific assumptions or
standardised assumptions, and whether the assumptions
used should be disclosed;
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EXTRACTIVE ACTIVITIES
(iii)
whether the following types of information should be
disclosed in the notes to the financial statements:
(A)
development and production schedules;
(B)
development and production costs; and
(C)
taxation and royalty obligations;
(g)
whether the disclosure of reconciliations of changes in reserve and
resource quantity estimates and changes in current value
measurements would provide useful information;
(h)
whether the reserve and resource quantity estimates and the
current value measurement should be required to be audited,
prepared by an independent consultant or prepared by a
competent person (as determined by relevant professional bodies),
noting that the competent person may be either an employee or
external to the entity; and
(i)
for users of oil and gas entity financial reports, whether they
currently use the US GAAP standardised measure of proved oil and
gas reserves in their analysis and, if so, how they use it and what
are the deficiencies (if any) in the standardised measure.
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